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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

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

(Amendment No. 1)

SCHEDULE 14A

Proxy Statement Pursuant to Section 14(a) of
the Securities Exchange Act of 1934

Filed by the Registrant ý
Filed by a Party other than the Registrant o
Check the appropriate box:
ý	Preliminary Proxy Statement
o	Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2))
o	Definitive Proxy Statement
o	Definitive Additional Materials
o	Soliciting Material under §240.14a-12

Centennial Resource Development, Inc.
(Name of Registrant as Specified In Its Charter)
N/A
(Name of Person(s) Filing Proxy Statement, if other than the Registrant)
Payment of Filing Fee (Check the appropriate box):
ý	No fee required.
o	Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11.
	(1)	Title of each class of securities to which transaction applies:
	(2)	Aggregate number of securities to which transaction applies:
	(3)	Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined):
	(4)	Proposed maximum aggregate value of transaction:
	(5)	Total fee paid:
o	Fee paid previously with preliminary materials.
o	Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing.
	(1)	Amount Previously Paid:
	(2)	Form, Schedule or Registration Statement No.:
	(3)	Filing Party:
	(4)	Date Filed:

PROXY STATEMENT FOR SPECIAL MEETING OF STOCKHOLDERS
OF CENTENNIAL RESOURCE DEVELOPMENT, INC.

Dear Stockholders of Centennial Resource Development, Inc.:

        You are cordially invited to attend the special meeting of stockholders of Centennial Resource Development, Inc. (the "Company," "we," "our" or "us"). At the special meeting, the Company's stockholders will be asked to consider and vote on proposals to:

(i)

approve, for purposes of complying with the applicable listing rules of The NASDAQ Capital Market (the "NASDAQ"), the issuance of 26,100,000 shares of our Class A Common Stock, par value $0.0001 per share (the "Class A Common Stock"), upon the conversion of 104,400 shares of our Series B Preferred Stock, par value $0.0001 per share, issued and sold to affiliates of Riverstone Investment Group LLC (together with its affiliates, "Riverstone") in private placements (the "Silverback Acquisition Private Placements"), the proceeds of which were used to fund a portion of the cash consideration for the acquisition of the leasehold interests and related upstream assets of Silverback Exploration, LLC and Silverback Operating, LLC (the "NASDAQ Proposal"); and



(ii)

approve the adjournment of the special meeting to a later date or dates, if necessary or appropriate, to permit further solicitation and vote of proxies in the event that there are insufficient votes for, or otherwise in connection with, the approval of the NASDAQ Proposal (the "Adjournment Proposal" and, together with the NASDAQ Proposal, the "Proposals").

Each of the Proposals is more fully described in the accompanying proxy statement, which each Company stockholder is encouraged to review carefully.

        The Company's Class A Common Stock and warrants, which are exercisable for shares of Class A Common Stock under certain circumstances, are currently listed on the NASDAQ under the symbols "CDEV" and "CDEVW," respectively.

        The Company is providing this proxy statement and accompanying proxy card to its stockholders in connection with the solicitation by our board of directors of proxies to be voted at the special meeting and any adjournments or postponements of the special meeting. Your vote is very important. Whether or not you plan to attend the special meeting in person, please submit your proxy card without delay.

We encourage you to read this proxy statement carefully. In particular, you should review the matters discussed under the caption "Risk Factors" beginning on page 12 of this proxy statement.

The Company's board of directors recommends that the Company's stockholders vote FOR the NASDAQ Proposal and FOR the Adjournment Proposal.

        Approval of the NASDAQ Proposal and the Adjournment Proposal requires the affirmative vote (in person or by proxy) of the holders of a majority of the outstanding shares of Class A Common Stock and Class C Common Stock, par value $0.0001 per share (together with the Class A Common Stock, the "Common Stock"), entitled to vote and actually cast thereon at the special meeting, voting as a single class. Holders of shares of Class A Common Stock issued and sold in the Silverback Acquisition Private Placements are not entitled to vote such shares at the special meeting. As of the record date, Riverstone held        % of the shares of Common Stock entitled to vote at the special meeting and will be able to control the outcome of the vote on the Proposals.

        If you sign, date and return your proxy card without indicating how you wish to vote, your proxy will be voted FOR each of the Proposals presented at the special meeting. If you fail to return your proxy card or fail to submit your proxy by telephone or over the Internet, or fail to instruct your bank, broker or other nominee how to vote, and do not attend the special meeting in person, the effect will be that your shares will not be counted for purposes of determining whether a quorum is present at the special meeting and, if a quorum is present, will have no effect on the Proposals. If you are a

stockholder of record and you attend the special meeting and wish to vote in person, you may withdraw your proxy and vote in person.

Thank you for your consideration of these matters.
Sincerely,


Mark G. Papa
Chief Executive Officer and Chairman
Centennial Resource Development, Inc.

Whether or not you plan to attend the special meeting of the Company's stockholders, please submit your proxy by completing, signing, dating and mailing the enclosed proxy card in the pre-addressed postage paid envelope or by using the telephone or Internet procedures provided to you by your broker or bank. If your shares are held in an account at a brokerage firm or bank, you must instruct your broker or bank on how to vote your shares or, if you wish to attend the special meeting of the Company's stockholders and vote in person, you must obtain a proxy from your broker or bank.

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

        This proxy statement is dated                        , 2017 and is first being mailed to the Company's stockholders on or about                        , 2017.

CENTENNIAL RESOURCE DEVELOPMENT, INC.

1401 Seventeenth Street, Suite 1000
Denver, Colorado 80202

NOTICE OF SPECIAL MEETING OF STOCKHOLDERS
OF CENTENNIAL RESOURCE DEVELOPMENT, INC.

To Be Held On                    , 2017

        To the Stockholders of Centennial Resource Development, Inc.:

        NOTICE IS HEREBY GIVEN that the special meeting of stockholders of Centennial Resource Development, Inc. (the "Company," "we," "our" or "us") will be held at              a.m., local time, on                    , 2017, at the Company's principal executive offices located at 1401 Seventeenth Street, Suite 1000, Denver, Colorado 80202 for the following purposes:

        1.     The NASDAQ Proposal—To consider and vote upon a proposal to approve, for purposes of complying with applicable listing rules of The NASDAQ Capital Market, the issuance of 26,100,000 shares of our Class A Common Stock, par value $0.0001 per share (the "Class A Common Stock"), upon the conversion of 104,400 shares of our Series B Preferred Stock, par value $0.0001 per share, issued and sold to affiliates of Riverstone Investment Group LLC (together with its affiliates, "Riverstone") in private placements (the "Silverback Acquisition Private Placements"), the proceeds of which were used to fund a portion of the cash consideration for the acquisition of the leasehold interests and related upstream assets of Silverback Exploration, LLC and Silverback Operating, LLC (the "NASDAQ Proposal").

        2.     The Adjournment Proposal—To consider and vote upon a proposal to approve the adjournment of the special meeting to a later date or dates, if necessary or appropriate, to permit further solicitation and vote of proxies if there are insufficient votes for, or otherwise in connection with, the approval of the NASDAQ Proposal (the "Adjournment Proposal" and, together with the NASDAQ Proposal, the "Proposals").

        Only holders of record of shares of Class A Common Stock and Class C Common Stock, par value $0.0001 per share (together with the Class A Common Stock, the "Common Stock") at the close of business on                    , 2017 are entitled to notice of the special meeting and to vote at the special meeting and any adjournments or postponements thereof. Holders of shares of Class A Common Stock issued and sold in the Silverback Acquisition Private Placements are not entitled to vote such shares at the special meeting. A complete list of the Company's stockholders of record entitled to vote at the special meeting will be available for ten days before the special meeting at the Company's principal executive offices for inspection by stockholders during ordinary business hours for any purpose germane to the special meeting. As of the record date, Riverstone held        % of the shares of Class A Common Stock and Class C Common Stock entitled to vote at the special meeting and will be able to control the outcome of the vote on the Proposals.

        Your attention is directed to the proxy statement accompanying this notice (including the annexes thereto) for a more complete description of each of the Proposals. We encourage you to read this proxy statement carefully. If you have any questions or need assistance voting your shares, please call our proxy solicitor, Morrow Sodali, at (877) 787-9239 (banks and brokers call collect at (203) 658-9400).

                    , 2017
By Order of the Board of Directors

Mark G. Papa
Chief Executive Officer and Director

Important Notice Regarding the Availability of Proxy Materials for the Special Meeting of Stockholders to be held on                    , 2017: This notice of meeting and the related proxy statement will be available at                    .

TABLE OF CONTENTS

CERTAIN DEFINED TERMS	ii
QUESTIONS AND ANSWERS ABOUT THE PROPOSALS	1
SELECTED HISTORICAL FINANCIAL INFORMATION	6
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS	10
RISK FACTORS	12
SPECIAL MEETING OF STOCKHOLDERS	39
PROPOSAL NO. 1—THE NASDAQ PROPOSAL	42
PROPOSAL NO. 2—THE ADJOURNMENT PROPOSAL	46
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	47
BENEFICIAL OWNERSHIP OF SECURITIES	76
HOUSEHOLDING INFORMATION	80
SUBMISSION OF STOCKHOLDER PROPOSALS	80
STOCKHOLDER PROPOSALS FOR 2017 ANNUAL MEETING	80
WHERE YOU CAN FIND ADDITIONAL INFORMATION	80
INDEX TO FINANCIAL STATEMENTS	F-1
ANNEX A: SUBSCRIPTION AGREEMENT (RIVERSTONE)	A-1
ANNEX B: SUBSCRIPTION AGREEMENT (OTHER INVESTORS)	B-1
ANNEX C: CERTIFICATE OF DESIGNATION	C-1
ANNEX D: NSAI RESERVE REPORTS	D-1
ANNEX E: GLOSSARY OF OIL AND NATURAL GAS TERMS	E-1

i

CERTAIN DEFINED TERMS

        Unless the context otherwise requires, references in this proxy statement to:

•

"Business Combination" are to our acquisition of approximately 89% of the outstanding membership interests in CRP from the Centennial Contributors, which closed on October 11, 2016, and the other transactions contemplated by the Contribution Agreement;

•

"Celero" are to Celero Energy Company, LP, a Delaware limited partnership;

•

"Centennial Contributors" are to CRD, NGP Follow-On and Celero, collectively;

•

The "Company," "we," "our" or "us" are to (a) Centennial Resource Development, Inc. and its subsidiaries, including CRP, following the closing of the Business Combination and (b) Silver Run Acquisition Corporation prior to the closing of the Business Combination;

•

"Class A Common Stock" are to our Class A Common Stock, par value $0.0001 per share;

•

"Class C Common Stock" are to our Class C Common Stock, par value $0.0001 per share, which were issued to the Centennial Contributors in connection with the Business Combination;

•

"Common Stock" or "voting common stock" are to our Class A Common Stock and Class C Common Stock;

•

"Contribution Agreement" are to the Contribution Agreement, dated as of July 6, 2016, among the Centennial Contributors, CRP and NewCo, as amended by Amendment No. 1 thereto, dated as of July 29, 2016, and the Joinder Agreement, dated as of October 7, 2016, by the Company;

•

"Conversion Shares" are to the 26,100,000 shares of Class A Common Stock issuable upon conversion of the shares of Series B Preferred Stock issued in the Silverback Acquisition Private Placements;

•

"CRD" are to Centennial Resource Development, LLC, a Delaware limited liability company;

•

"CRP" are to Centennial Resource Production, LLC, a Delaware limited liability company;

•

"IPO" are to our initial public offering of units, which closed on February 29, 2016;

•

"NewCo" are to New Centennial, LLC, a Delaware limited liability company controlled by affiliates of Riverstone;

•

"NGP Follow-On" are to NGP Centennial Follow-On LLC, a Delaware limited liability company;

•

"Private Placement Warrants" are to our 8,000,000 outstanding warrants, which were purchased by our Sponsor in a private placement simultaneously with the closing of our IPO;

•

"Public Warrants" are to our 16,666,643 outstanding warrants, which were sold as part of the Units in our IPO;

•

"Riverstone" are to Riverstone Investment Group LLC and its affiliates, including our Sponsor, collectively;

•

"Riverstone Purchasers" are to Riverstone VI Centennial QB Holdings, L.P., Riverstone Non-ECI USRPI AIV, L.P. and REL US Centennial Holdings, LLC, which are affiliates of Riverstone;

•

"Series B Preferred Stock" are to our Series B Preferred Stock, par value $0.0001 per share;

ii

•

"Silverback Acquisition" are to our acquisition of the leasehold interests and related upstream assets of Silverback Exploration, LLC and Silverback Operating, LLC, which closed on December 28, 2016;

•

"Silverback Acquisition Private Placements" are to the issuance and sale in private placements of (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, which closed simultaneously with the consummation of the Silverback Acquisition;

•

"Sponsor" are to our sponsor, Silver Run Sponsor, LLC, a Delaware limited liability company and an affiliate of Riverstone;

•

"Units" are to our units sold in our IPO, each of which consisted of one share of Class A Common Stock and one-third of one Public Warrant; and

•

"Warrants" are to the Private Placement Warrants and the Public Warrants.

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

iii

QUESTIONS AND ANSWERS ABOUT THE PROPOSALS

The following questions and answers briefly address some commonly asked questions about the proposals to be presented at the special meeting of stockholders of Centennial Resource Development, Inc. (the "Company," "we," "our" or "us"). The following questions and answers do not include all the information that is important to Company stockholders. We urge Company stockholders to read carefully this entire proxy statement, including the annexes and other documents referred to herein.

Q:

Why am I receiving this proxy statement?

A:

The Company's stockholders are being asked to consider and vote upon, among other things, a proposal to approve, for purposes of complying with applicable listing rules of The NASDAQ Capital Market (the "NASDAQ"), the issuance of 26,100,000 shares of our Class A Common Stock, par value $0.0001 per share (the "Class A Common Stock" and such shares, the "Conversion Shares"), upon the conversion of 104,400 shares of our Series B Preferred Stock, par value $0.0001 per share (the "Series B Preferred Stock"), issued and sold to certain affiliates of Riverstone Investment Group LLC (together with its affiliates, "Riverstone" and the purchasers of the Series B Preferred Stock, the "Riverstone Purchasers") in private placements (the "Silverback Acquisition Private Placements"), the proceeds of which were used to fund a portion of the cash consideration for the acquisition of the leasehold interests and related upstream assets of Silverback Exploration, LLC and Silverback Operating, LLC (the "Silverback Acquisition").

This proxy statement and its annexes contain important information about the proposals to be acted upon at the special meeting. You should read this proxy statement and its annexes carefully and in their entirety.

Your vote is important. You are encouraged to submit your proxy as soon as possible after carefully reviewing this proxy statement and its annexes.

Q:

What is being voted on at the special meeting?

A:

Below are the proposals on which the Company's stockholders will vote at the special meeting.

1.

The NASDAQ Proposal—To approve, for purposes of complying with applicable listing rules of the NASDAQ, the issuance of the Conversion Shares (the "NASDAQ Proposal").

2.

The Adjournment Proposal—To approve the adjournment of the special meeting to a later date or dates, if necessary or appropriate, to permit further solicitation and vote of proxies if there are insufficient votes for, or otherwise in connection with, the approval of the NASDAQ Proposal (the "Adjournment Proposal" and, together with the NASDAQ Proposal, the "Proposals"). The Adjournment Proposal will only be presented at the special meeting if there are not sufficient votes to approve the NASDAQ Proposal.

Q:

Are the Proposals conditioned on one another?

A:

No. Neither the NASDAQ Proposal nor the Adjournment Proposal is conditioned on the approval of the other Proposal.

Q:

Why is the Company providing stockholders with the opportunity to vote on the conversion of the Series B Preferred Stock?

A:

The Company is proposing the NASDAQ Proposal in order to comply with NASDAQ Listing Rules, which require stockholder approval of certain transactions that result in the issuance of 20% or more of a company's outstanding voting power or shares of common stock outstanding before the issuance of stock or securities. In connection with the Silverback Acquisition Private

1

Placements, the Company issued an aggregate of 36,485,970 shares of Class A Common Stock, representing 19.9% of the shares of Class A Common Stock and Class C Common Stock, par value $0.0001 (the "Class C Common Stock" and, together with the Class A Common Stock, the "Common Stock") outstanding prior to the Silverback Acquisition Private Placements. The issuance of the Conversion Shares upon the conversion of the Series B Preferred Stock issued in the Silverback Acquisition Private Placements, representing an additional 14.2% of the shares of Common Stock outstanding prior to the Silverback Acquisition Private Placements, is therefore subject to stockholder approval under NASDAQ Rule 5635 (d). See the section entitled "Proposal No. 1—The NASDAQ Proposal" for additional information.

Q:

What will happen if the NASDAQ Proposal is not approved at the special meeting?

A:

If the NASDAQ Proposal is not approved at the special meeting or at a subsequent meeting of our stockholders held to approve a similar proposal, the shares of Series B Preferred Stock will not be converted into shares of Class A Common Stock and will remain outstanding in accordance with the terms set forth in the Certificate of Designation of Series B Preferred Stock of Centennial Resource Development, Inc. (the "Certificate of Designation"). For so long as the shares of Series B Preferred Stock remain outstanding, the holders thereof will not be entitled to vote on any matter on which stockholders are generally entitled to vote, but will have the right to participate pro rata in any future distributions paid on shares of our Class A Common Stock on an as-converted basis. See the section entitled "Proposal No. 1—The NASDAQ Proposal—Certificate of Designation" for additional information.

Whether the NASDAQ Proposal is approved at the special meeting will have no effect on the Silverback Acquisition, which was completed on December 28, 2016.

Q:

What is the relationship between the Company, Riverstone and the Riverstone Purchasers?

A:

As of the date hereof, Riverstone and its affiliates are the holders of shares of Class A Common Stock and Series B Preferred Stock representing a 54.2% economic interest and a 44.0% voting interest in the Company. As of the record date, the shares of Class A Common Stock owned by Riverstone that are entitled to vote at the special meeting represented        % of the shares of Common Stock entitled to vote at the special meeting. Riverstone also owns all of our outstanding Private Placement Warrants. The Riverstone Purchasers are investment funds managed or controlled by Riverstone.

Q:

What equity stake will the Company's public stockholders, Riverstone and the Centennial Contributors hold in the Company if the NASDAQ Proposal approving the conversion of the Series B Preferred Stock is approved?

A:

It is anticipated that, if the NASDAQ Proposal is approved and upon the conversion of the Series B Preferred Stock approved thereby, the ownership of the Company will be as follows:

•

public stockholders will own 103,976,459 shares of our Class A Common Stock, representing a 45.82% economic interest and a 42.25% voting interest;

•

Riverstone will own 122,958,590 shares of our Class A Common Stock, representing a 54.18% economic interest and a 49.96% voting interest;

•

the Centennial Contributors will own 19,155,921 shares of our Class C Common Stock, representing a 0% economic interest and a 7.78% voting interest; and

•

CRD will own one share of our Series A Preferred Stock, par value $0.0001 per share, representing a 0% economic interest and limited voting interest.

2

Q:

What happens if I sell my shares of Class A Common Stock before the special meeting?

A:

The record date for the special meeting is            , 2017. If you transfer your shares of Common Stock after the record date, but before the special meeting, unless the transferee obtains from you a proxy to vote those shares, you will retain your right to vote at the special meeting. If you transfer your shares of Common Stock prior to the record date, you will have no right to vote those shares at the special meeting.

Q:

What vote is required to approve the Proposals presented at the special meeting?

A:

Approval of the NASDAQ Proposal and the Adjournment Proposal requires the affirmative vote (in person or by proxy) of the holders of the majority of the outstanding shares of Class A Common Stock and Class C Common Stock, voting as a single class, entitled to vote and actually cast thereon at the special meeting. The holders of shares of Class A Common Stock issued in the Silverback Acquisition Private Placements are not entitled to vote such shares in favor of the NASDAQ Proposal and will not be considered in determining the number of shares that constitutes a majority of the outstanding shares of Common Stock. As of the record date, Riverstone held        % of the shares of Common Stock entitled to vote at the special meeting and will be able to control the outcome of the vote on the Proposals. Riverstone has advised the Company that it intends to vote all of the shares of Common Stock held by it in favor of each of the Proposals at the special meeting.

Q:

How many votes do I have at the special meeting?

A:

Each of the Company's stockholders is entitled to one vote at the special meeting for each share of Common Stock (other than shares of Class A Common Stock issued in the Silverback Acquisition Private Placements) held of record as of            , 2017, the record date for the special meeting. As of the close of business on the record date, there were            outstanding shares of Common Stock entitled to vote at the special meeting.

Q:

What constitutes a quorum at the special meeting?

A:

Holders of a majority in voting power of Common Stock issued and outstanding and entitled to vote at the special meeting, present in person or represented by proxy, constitute a quorum. Because shares of Class A Common Stock issued in the Silverback Acquisition Private Placements are not entitled to vote at the special meeting, they are not counted for purposes of determining the holders that constitute a quorum. In the absence of a quorum, the chairman of the meeting has the power to adjourn the special meeting. As of the record date for the special meeting,             shares of Common Stock would be required to achieve a quorum.

Q:

What interests do the current officers and directors have in the NASDAQ Proposal?

A:

In considering the recommendation of our board of directors to approve the NASDAQ Proposal, stockholders should be aware that several of our directors have relationships with Riverstone. As of the record date, Riverstone owned approximately        % of our Class A Common Stock,         % of our voting stock and all of the outstanding shares of Series B Preferred Stock. If the NASDAQ Proposal is approved at our special meeting, Riverstone will receive shares of Class A Common Stock upon the automatic conversion of its shares of Series B Preferred Stock. See the section entitled "Proposal No. 1—The NASDAQ Proposal—Interests of Certain Persons in the NASDAQ Proposal" for additional information.

3

Q:

Do I have appraisal rights if I vote against the NASDAQ Proposal?

A:

No. There are no appraisal rights available to holders of Common Stock in connection with the NASDAQ Proposal.

Q:

What do I need to do now?

A:

You are urged to read carefully and consider the information contained in this proxy statement, including "Risk Factors" and the annexes, and to consider how the Proposals will affect you as a stockholder. You should then vote as soon as possible in accordance with the instructions provided in this proxy statement and on the enclosed proxy card or, if you hold your shares through a brokerage firm, bank or other nominee, on the voting instruction form provided by the broker, bank or nominee.

Q:

How do I vote?

A:

If you were a holder of record of Common Stock (other than shares of Class A Common Stock issued in the Silverback Acquisition Private Placements) on                , 2017, the record date for the special meeting of Company stockholders, you may vote with respect to the proposals in person at the special meeting or by completing signing, dating and returning the enclosed proxy card in the postage-paid envelope provided. If you hold your shares in "street name," which means your shares are held of record by a broker, bank or other nominee, you should follow the instructions provided by your broker, bank or nominee to ensure that votes related to the shares you beneficially own are properly counted. In this regard, you must provide the record holder of your shares with instructions on how to vote your shares or, if you wish to attend the special meeting and vote in person, obtain a proxy from your broker, bank or nominee.

Q:

What will happen if I abstain from voting or fail to vote at the special meeting?

A:

At the special meeting, the Company will count a properly executed proxy marked "ABSTAIN" with respect to a particular proposal as present for purposes of determining whether a quorum is present. For purposes of approval, failure to vote or an abstention will have no effect on the NASDAQ Proposal or the Adjournment Proposal.

Q:

What will happen if I sign and submit my proxy card without indicating how I wish to vote?

A:

Signed and dated proxies received by the Company without an indication of how the stockholder intends to vote on a proposal will be voted "FOR" each Proposal presented to the stockholders.

Q:

If I am not going to attend the special meeting in person, should I submit my proxy card instead?

A:

Yes. Whether you plan to attend the special meeting or not, please read the enclosed proxy statement carefully, and vote your shares by completing, signing, dating and returning the enclosed proxy card in the postage-paid envelope provided.

Q:

If my shares are held in "street name," will my broker, bank or nominee automatically vote my shares for me?

A:

No. Under the rules of various national and regional securities exchanges, your broker, bank, or nominee cannot vote your shares with respect to non-discretionary matters unless you provide instructions on how to vote in accordance with the information and procedures provided to you by your broker, bank, or nominee. The Company believes the Proposals presented to the stockholders will be considered non-discretionary and therefore your broker, bank, or nominee cannot vote your shares without your instruction. Your broker, bank or nominee can vote your shares only if you provide instructions on how to vote. You should instruct your broker, bank or nominee to vote your shares in accordance with directions you provide.

4

Q:

May I change my vote after I have submitted my executed proxy card?

A:

Yes. You may change your vote by sending a later-dated, signed proxy card to the Company's secretary at the address listed below so that it is received by our secretary prior to the special meeting or attend the special meeting in person and vote. You also may revoke your proxy by sending a notice of revocation to the Company's secretary, which must be received prior to the special meeting.

Q:

What should I do if I receive more than one set of voting materials?

A:

You may receive more than one set of voting materials, including multiple copies of this proxy statement and multiple proxy cards or voting instruction cards. For example, if you hold your shares in more than one brokerage account, you will receive a separate voting instruction card for each brokerage account in which you hold shares. If you are a holder of record and your shares are registered in more than one name, you will receive more than one proxy card. Please complete, sign, date and return each proxy card and voting instruction card that you receive in order to cast your vote with respect to all of your shares.

Q:

Who can help answer my questions?

A:

If you have questions about the Proposals or if you need additional copies of the proxy statement or the enclosed proxy card you should contact:

Centennial Resource Development, Inc.
1401 Seventeenth Street, Suite 1000
Denver, Colorado 80202
Attention: Secretary

You may also contact our proxy solicitor at:

Morrow Sodali LLC
470 West Avenue
Stamford, Connecticut 06902
Stockholders please call: (877) 787-9239
Banks and Brokers please call: (203) 658-9400
Email: CDEV.info@morrowsodali.com

To obtain timely delivery, our stockholders must request the materials no later than five (5) business days prior to the special meeting.

You may also obtain additional information about the Company from documents filed with the United States Securities and Exchange Commission (the "SEC") by following the instructions in the section entitled "Where You Can Find More Information."

Q:

Who will solicit and pay the cost of soliciting proxies?

A:

The Company will pay the cost of soliciting proxies for the special meeting. The Company has engaged Morrow Sodali ("Morrow Sodali"), to assist in the solicitation of proxies for the special meeting. The Company has agreed to pay Morrow Sodali a fee of $6,500, plus disbursements. The Company will reimburse Morrow Sodali for reasonable out-of-pocket expenses and will indemnify Morrow Sodali and its affiliates against certain claims, liabilities, losses, damages and expenses. The Company will also reimburse banks, brokers and other custodians, nominees and fiduciaries representing beneficial owners of shares of Class A Common Stock for their expenses in forwarding soliciting materials to beneficial owners of Class A Common Stock and in obtaining voting instructions from those owners. Our directors, officers and employees may also solicit proxies by telephone, by facsimile, by mail, on the Internet or in person. They will not be paid any additional amounts for soliciting proxies.

5

SELECTED HISTORICAL FINANCIAL INFORMATION

        The following table shows selected historical financial information of Centennial Resource Production, LLC, a Delaware limited liability company ("CRP"), our accounting predecessor, 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 proxy statement. 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 proxy statement.

        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 proxy statement.

	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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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        Certain statements in this proxy statement constitute "forward-looking statements." All statements, other than statements of historical fact included in this proxy statement, 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 proxy statement, 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:

•

our business strategy;

•

our reserves;

•

our drilling prospects, inventories, projects and programs;

•

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

•

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

•

our realized oil, natural gas and natural gas liquids ("NGL") prices;

•

the timing and amount of our future production of oil, natural gas and NGLs;

•

our hedging strategy and results;

•

our future drilling plans;

•

our competition and government regulations;

•

our ability to obtain permits and governmental approvals;

•

our pending legal or environmental matters;

•

our marketing of oil, natural gas and NGLs;

•

our leasehold or business acquisitions;

•

our costs of developing our properties;

•

general economic conditions;

•

credit markets;

•

uncertainty regarding our future operating results; and

•

our plans, objectives, expectations and intentions contained in this proxy statement that are not historical.

        We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the 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 proxy statement 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 proxy statement 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 proxy statement.

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RISK FACTORS

The following risk factors are not exhaustive and investors are encouraged to perform their own investigation with respect to our business, financial condition and prospects. You should carefully consider the following risk factors in addition to the other information included in this proxy statement, including matters addressed in the section entitled "Cautionary Note Regarding Forward-Looking Statements." We may face additional risks and uncertainties that are not presently known to us, or that we currently deem immaterial, which may also impair our business or financial condition. The following discussion should be read in conjunction with our financial statements and notes to the financial statements included herein.

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:

•

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

•

the price and quantity of foreign imports of oil, natural gas and NGLs;

•

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

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•

actions of the Organization of the Petroleum Exporting Countries ("OPEC"), its members and other state-controlled oil companies relating to oil price and production controls;

•

the level of global exploration, development and production;

•

the level of global inventories;

•

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

•

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

•

localized and global supply and demand fundamentals and transportation availability;

•

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

•

weather conditions and other natural disasters;

•

technological advances affecting energy consumption;

•

the price and availability of alternative fuels;

•

expectations about future commodity prices; and

•

U.S. federal, state and local and non-U.S. governmental regulation and taxes.

        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

13

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:

•

the prices at which our production is sold;

•

our proved reserves;

•

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

•

our ability to acquire, locate and produce new reserves;

•

the levels of our operating expenses; and

•

CRP's ability to borrow under its revolving credit facility and the ability to access the capital markets.

        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:

•

landing a wellbore in the desired drilling zone;

•

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

•

running our casing the entire length of the wellbore; and

•

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

        Risks that we face while completing wells include the following:

•

the ability to fracture stimulate the planned number of stages;

•

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

•

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

        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:

•

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

•

pressure or irregularities in geological formations;

15

•

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

•

equipment failures, accidents or other unexpected operational events;

•

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

•

lack of available capacity on interconnecting transmission pipelines;

•

adverse weather conditions;

•

issues related to compliance with environmental regulations;

•

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

•

declines in oil and natural gas prices;

•

limited availability of financing at acceptable terms;

•

title problems; and

•

limitations in the market for oil and natural gas.

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:

•

our senior management's attention may be diverted from the management of daily operations to the integration of the properties acquired in the Silverback Acquisition;

•

we could incur significant unknown and contingent liabilities for which we have limited or no contractual remedies or insurance coverage;

•

the properties acquired in the Silverback Acquisition may not perform as well as we anticipate;

•

unexpected costs, delays and challenges may arise in integrating the properties acquired in the Silverback Acquisition into our existing operations; and

•

we may need to hire additional staff, devote additional resources and contract additional rigs to integrate the properties acquired in the the Silverback Acquisition.

        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 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.

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        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:

•

incur additional indebtedness;

•

make loans to others;

•

make investments;

•

merge or consolidate with another entity;

•

make certain payments;

•

hedge future production or interest rates;

•

incur liens;

•

sell assets; and

•

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

        In addition, 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 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.

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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:

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

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

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

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

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

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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:

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the timing and amount of capital expenditures;

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the operator's expertise and financial resources;

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the approval of other participants in drilling wells;

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the selection of technology; and

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the rate of production of reserves, if any.

        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:

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

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abnormally pressured formations;

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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse; fire, explosions and ruptures of pipelines;

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personal injuries and death;

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natural disasters; and

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

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

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injury or loss of life;

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

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pollution and other environmental damage;

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regulatory investigations and penalties; and

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repair and remediation costs.

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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:

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unexpected drilling conditions;

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title problems;

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pressure or lost circulation in formations;

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equipment failure or accidents;

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adverse weather conditions;

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compliance with environmental and other governmental or contractual requirements; and

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

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

        In the future we may make acquisitions of 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:

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increased responsibilities for our executive level personnel;

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increased administrative burden;

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increased capital requirements; and

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increased organizational challenges common to large, expansive operations.

        Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information of CRP included elsewhere in this proxy statement 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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recoverable reserves;

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future oil and natural gas prices and their applicable differentials;

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operating costs; and

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potential environmental and other liabilities.

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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 proxy statement 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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changes in the valuation of our deferred tax assets and liabilities;

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expected timing and amount of the release of any tax valuation allowances;

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tax effects of stock-based compensation;

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costs related to intercompany restructurings;

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changes in tax laws, regulations or interpretations thereof; or

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•

lower than anticipated future earnings in jurisdictions where we have lower statutory tax rates and higher than anticipated future earnings in jurisdictions where we have higher statutory tax rates.

        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:

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actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to us;

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changes in the market's expectations about our operating results;

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success of competitors;

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our operating results failing to meet the expectation of securities analysts or investors in a particular period;

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changes in financial estimates and recommendations by securities analysts concerning us or its markets in general;

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operating and stock price performance of other companies that investors deem comparable to us;

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our ability to market new and enhanced products on a timely basis;

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changes in laws and regulations affecting our business;

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commencement of, or involvement in, litigation involving us;

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changes in our capital structure, such as future issuances of securities or the incurrence of additional debt;

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the volume of securities available for public sale;

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any major change in our board or management;

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sales of substantial amounts of our securities by our directors, executive officers or significant stockholders or the perception that such sales could occur; and

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general economic and political conditions such as recession; interest rate, fuel price, and international currency fluctuations; and acts of war or terrorism.

        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:

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a majority of its board of directors consist of independent directors (as defined under the NASDAQ corporate governance standards);

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its nominating and corporate governance committee consists entirely of independent directors; and

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the compensation of its executive officers be determined, or recommended to the board for determination, by a majority of independent directors in a vote by independent directors, or by a compensation committee comprised solely of independent directors.

        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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no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates;

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the exclusive right of our board of directors to elect a director to fill a vacancy created by the expansion of the board of directors or the resignation, death, or removal of a director, which prevents stockholders from being able to fill vacancies on our board of directors;

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the ability of our board of directors to determine whether to issue shares of our preferred stock and to determine the price and other terms of those shares, including preferences and voting rights, without stockholder approval, which could be used to significantly dilute the ownership of a hostile acquirer;

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a prohibition on stockholder action by written consent, which forces stockholder action to be taken at an annual or special meeting of our stockholders;

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the requirement that an annual meeting of stockholders may be called only by the chairman of the board of directors, the chief executive officer, or the board of directors, which may delay the ability of our stockholders to force consideration of a proposal or to take action, including the removal of directors;

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•

limiting the liability of, and providing indemnification to, our directors and officers;

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controlling the procedures for the conduct and scheduling of stockholder meetings;

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providing that directors may be removed prior to the expiration of their terms by stockholders only for cause; and

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advance notice procedures that stockholders must comply with in order to nominate candidates to our board of directors or to propose matters to be acted upon at a stockholders' meeting, which may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer's own slate of directors or otherwise attempting to obtain control of the Company.

        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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SPECIAL MEETING OF STOCKHOLDERS

General

        The Company is furnishing this proxy statement to its stockholders as part of the solicitation of proxies by our board of directors for use at the special meeting of stockholders to be held on                    , 2017, and at any adjournment or postponement thereof. This proxy statement is first being furnished to our stockholders on or about                     , 2017. This proxy statement provides you with information you need to know to be able to vote or instruct your vote to be cast at the special meeting.

Date, Time and Place

        The special meeting will be held at                     a.m., local time, on                    , 2017, at the Company's principal executive offices located at 1401 Seventeenth Street, Suite 1000, Denver, Colorado 80202, or such other date, time and place to which such meeting may be adjourned or postponed, to consider and vote upon the proposals.

Voting Power; Record Date

        You will be entitled to vote or direct votes to be cast at the special meeting if you owned shares of Common Stock at the close of business on                     , 2017, which is the record date for the special meeting. You are entitled to one vote for each share of Common Stock that you owned as of the close of business on the record date, except that shares of Class A Common Stock issued in the Silverback Acquisition Private Placements are not entitled to vote at the special meeting. If your shares are held in "street name" or are in a margin or similar account, you should contact your broker, bank or nominee to ensure that votes related to the shares you beneficially own are properly counted. On the record date, there were                     shares of Common Stock outstanding in the aggregate, of which                    were shares of Common Stock entitled to vote at the special meeting.

Quorum and Required Vote for Proposals for the Special Meeting

        A quorum of the Company's stockholders is necessary to hold a valid meeting. A quorum will be present at the special meeting if a majority of the Common Stock outstanding and entitled to vote at the special meeting is represented in person or by proxy. Because shares of Class A Common Stock issued in the Silverback Acquisition Private Placements are not entitled to vote at the special meeting, they are not counted for purposes of determining the holders that constitute a quorum. Abstentions will count as present for the purposes of establishing a quorum.

        The approval of the NASDAQ Proposal and the Adjournment Proposal requires the affirmative vote of holders of a majority of the shares of Common Stock represented in person or by proxy and entitled to vote and actually cast thereon at the special meeting. Accordingly, a stockholder's failure to vote by proxy or to vote in person at the special meeting will not be counted towards the number of shares of Class A Common Stock required to validly establish a quorum, and if a valid quorum is otherwise established, it will have no effect on the outcome of any vote on the NASDAQ Proposal or the Adjournment Proposal.

        As of the record date, Riverstone held        % of the shares of Common Stock entitled to vote at the special meeting and will be able to control the outcome of the vote on the Proposals. Riverstone has advised the Company that it intends to vote all of the shares of Common Stock held by it in favor of each of the Proposals at the special meeting.

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Recommendation to Our Stockholders

        After careful consideration, the Company's board of directors recommends that the Company's stockholders vote "FOR" each Proposal being submitted to a vote of the Company's stockholders at the special meeting.

        For a more complete description of the Company's reasons for the Silverback Acquisition Private Placements and the recommendation of the Company's board of directors, see the section entitled "Proposal No. 1—The NASDAQ Proposal."

Voting Your Shares

        Each share of Common Stock (other than shares of Class A Common Stock issued in the Silverback Acquisition Private Placements) that you own in your name entitles you to one vote on each of the Proposals at the special meeting. Your one or more proxy cards show the number of shares of Common Stock that you own. There are several ways to vote your shares of Common Stock:

•

You can vote your shares of Common Stock by completing, signing, dating and returning the enclosed proxy card in the postage-paid envelope provided. If you hold your shares in "street name" through a bank, broker or other nominee, you will need to follow the instructions provided to you by your bank, broker or other nominee to ensure that your shares are represented and voted at the special meeting. If you vote by proxy card, your "proxy," whose name is listed on the proxy card, will vote your shares as you instruct on the proxy card. If you sign and return the proxy card but do not give instructions on how to vote your shares, your shares of Common Stock will be voted as recommended by the board of directors. The board of directors recommends voting "FOR" the NASDAQ Proposal and "FOR" the Adjournment Proposal.

•

You can attend the special meeting and vote in person even if you have previously voted by submitting a proxy pursuant to any of the methods noted above. You will be given a ballot when you arrive. However, if your shares of Common Stock are held in the name of your broker, bank or nominee, you must get a proxy from the broker, bank or nominee. That is the only way we can be sure that the broker, bank or nominee has not already voted your shares of Common Stock.

Revoking Your Proxy

        If you give a proxy, you may revoke it at any time before the special meeting or at such meeting by doing any one of the following:

•

you may send another proxy card with a later date;

•

you may notify the Company's secretary, in writing, before the special meeting that you have revoked your proxy; or

•

you may attend the special meeting, revoke your proxy, and vote in person, as indicated above.

No Additional Matters May Be Presented at the Special Meeting

        The special meeting has been called to consider only the approval of the NASDAQ Proposal and the Adjournment Proposal. Under our bylaws, other than procedural matters incident to the conduct of the special meeting, no other matters may be considered at the special meeting if they are not included in this proxy statement, which serves as the notice of the special meeting.

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Who Can Answer Your Questions About Voting Your Shares or Warrants

        If you have any questions about how to vote or direct a vote in respect of your shares of Common Stock, you may call Morrow Sodali, our proxy solicitor, at (877) 787-9239 (banks and brokerage firms, please call collect: (203) 658-9400).

Appraisal Rights

        Appraisal rights are not available to holders of shares of Common Stock in connection with the Proposals being voted on at the special meeting.

Proxy Solicitation Costs

        The Company is soliciting proxies on behalf of its board of directors. This solicitation is being made by mail but also may be made by telephone or in person. The Company and its directors, officers and employees may also solicit proxies in person. The Company will file with the SEC all scripts and other electronic communications as proxy soliciting materials. The Company will bear the cost of the solicitation.

        The Company has hired Morrow Sodali to assist in the proxy solicitation process. The Company will pay that firm a fee of $6,500, plus disbursements. The Company will ask banks, brokers and other institutions, nominees and fiduciaries to forward the proxy materials to their principals and to obtain their authority to execute proxies and voting instructions. The Company will reimburse them for their reasonable expenses.

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PROPOSAL NO. 1—THE NASDAQ PROPOSAL

Overview

        On December 28, 2016, we completed the acquisition of the leasehold interests and related upstream assets of Silverback Exploration, LLC and Silverback Operating, LLC (collectively, "Silverback" and such acquisition, the "Silverback Acquisition") for a cash purchase price of approximately $855,000,000, subject to customary purchase price adjustments. The assets acquired from Silverback include 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 shales.

        In connection with the Silverback Acquisition, we issued and sold in private placements that closed simultaneously with the Silverback Acquisition (the "Silverback Acquisition Private Placements") (i) 3,473,590 shares of Class A Common Stock and 104,400 shares of Series B Preferred Stock to Riverstone VI Centennial QB Holdings, L.P., Riverstone Non-ECI USRPI AIV, L.P. and REL US Centennial Holdings, LLC, which are affiliates of Riverstone (the "Riverstone Purchasers"), and (ii) 33,012,380 shares of our Class A Common Stock to certain other investors, resulting in aggregate gross proceeds of approximately $910 million. We used the proceeds from the Silverback Acquisition 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) if and at such time as we receive stockholder approval of the NASDAQ Proposal. If the NASDAQ Proposal is not approved at the special meeting or at a subsequent meeting of our stockholders held to approve a similar proposal, the shares of Series B Preferred Stock will not be converted into shares of Class A Common Stock and will remain outstanding in accordance with the terms set forth in the Certificate of Designation. Whether the NASDAQ Proposal is approved at the special meeting will have no effect on the completed Silverback Acquisition.

        For further information, please see "—Subscription Agreements" below and the full text of the Subscription Agreement, dated as of November 27, 2016, between the Company and an affiliate of Riverstone (that was subsequently assigned to the Riverstone Purchasers) (the "Riverstone Subscription Agreement"), which is attached to this proxy statement as Annex A, and the full text of the form of Subscription Agreement, dated as of December 2, 2016, between the Company and each of the investors party thereto (the "Investor Subscription Agreements" and, together with the Riverstone Subscription Agreement, the "Subscription Agreements"), which is attached to this proxy statement as Annex B. Please see also "—Certificate of Designation" below and the full text of the Certificate of Designation, which is attached to this proxy statement as Annex C. The discussion herein is qualified in its entirety by reference to such documents.

Reasons for the Silverback Acquisition Private Placements

        Our board of directors determined that the Silverback Acquisition Private Placements were advisable, fair to and in our best interest and in the best interest of our stockholders. We conducted the Silverback Acquisition Private Placements in order to raise funds for the cash consideration for the Silverback Acquisition and for general corporate purposes. Upon the closing of the Silverback Acquisition Private Placements, we received approximately $910 million in gross proceeds, including approximately $380 million in gross proceeds from the sale of the Series B Preferred Stock.

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Why the Company Needs Stockholder Approval

        We are seeking stockholder approval of the NASDAQ Proposal in order to comply with NASDAQ Listing Rule 5635(d).

        Under NASDAQ Listing Rule 5635(d), stockholder approval is required for a transaction other than a public offering involving the sale, issuance or potential issuance by an issuer of common stock (or securities convertible into or exercisable for common stock) at a price that is less than the greater of book or market value of the stock if the number of shares of common stock to be issued is or may be equal to 20% or more of the common stock, or 20% or more of the voting power, outstanding before the issuance. In the Silverback Acquisiton Private Placements, the Company issued 36,485,970 shares of Class A Common Stock, representing 19.9% of the number of shares of Common Stock outstanding prior to the Silverback Acquisition Private Placements, and, following the approval of the NASDAQ Proposal and the conversion of the Series B Preferred Stock issued in the Silverback Acquisition Private Placements, the Company will issue 26,100,000 Converesion Shares, representing an additional 14.2% of the shares of Common Stock outstanding prior to the Silverback Acquisition Private Placements. The shares of Class A Common Stock and Series B Preferred Stock issued in the Silverback Acquisition Private Placements were issued at a price (in the case of the Series B Preferred Stock, on an as-converted basis) that was less than the market value of the Class A Common Stock on the date of entry into the Subscription Agreements and the the date of closing of the Silverback Acquisition Private Placements, and the issuance of the Conversion Shares is therefore subject to stockholder approval under NASDAQ Rule 5635(d).

Subscription Agreements

        In connection with the Silverback Acquisition, the Company entered into a subscription agreement (the "Riverstone Subscription Agreement"), dated as of November 27, 2016 (as amended on December 22, 2016), with an affiliate of Riverstone (the "Riverstone subscriber"), pursuant to which the Riverstone subscriber agreed to purchase up to approximately $500 million of the Company's equity securities in shares of Class A Common Stock at $14.54 per share and shares of Series B Preferred Stock at $3,635 per share (or $14.54 per share on an as-converted basis). The Riverstone subscriber had the right to assign its rights under the Riverstone Subscription Agreement to other persons, and subsequently elected to make the assignment to the Riverstone Purchasers. The Riverstone Subscription Agreement provided that, if the number of shares of Class A Common Stock to be issued to the Riverstone Purchasers, together with additional shares of Class A Common Stock issued to finance the Silverback Acquisition, would otherwise exceed 19.9% of the Company's issued and outstanding shares of Class A Common Stock, then the Riverstone Purchasers would purchase a number of shares of Class A Common Stock such that the 19.9% limitation would not be exceeded and would purchase the remaining commitment in shares of Series B Preferred Stock. On December 28, 2016, in connection with the closing of the Silverback Acquisition, the Riverstone Purchasers purchased an aggregate of 3,473,590 shares of Class A Common Stock and 104,400 shares of Series B Preferred Stock for aggregate gross proceeds of approximately $430 million.

        On December 2, 2016, the Company entered into separate subscription agreements (together with the Riverstone Subscription Agreement, the "Subscription Agreements"), with certain other investors, pursuant to which such investors agreed to purchase 33,012,380 shares of Class A Common Stock at $14.54 per share for aggregate gross proceeds of approximately $480 million.

        The shares of Class A Common Stock and Series B Preferred Stock issued pursuant to the Subscription Agreements were not registered under the Securities Act in reliance upon the exemption provided in Section 4(a)(2) of the Securities Act. The Subscription Agreements provide that the Company must register the resale of the shares of Class A Common Stock issued thereunder pursuant to a registration statement that must be filed within 75 calendar days after consummation of the

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Silverback Acquisition. The Company must use its commercially reasonable efforts to have the registration statement declared effective as soon as practicable, but in any event no later than the earlier of (i) the 90^th calendar day after its initial filing and (ii) the 10^th business day after the Company is notified by the SEC that the registration statement will not be reviewed or subject to further review.

Certificate of Designation

        Upon the closing of the Silverback Acquisition, we filed with the Secretary of State of the State of Delaware the Certificate of Designation, which sets forth the terms, rights, obligations and preferences of the Series B Preferred Stock issued to the Riverstone Purchasers.

        Description of Series B Preferred Stock.    Our Series B Preferred Stock is a newly issued class of preferred stock, with a par value of $0.0001 per share. The Riverstone Purchasers own all of the outstanding shares of our Series B Preferred Stock, and prior to the date of the special meeting to which this proxy statement relates may not transfer, sell, pledge or otherwise dispose of the Series B Preferred Stock without our prior written consent, except to an affiliate of the applicable Riverstone Purchaser or us. The holders of the Series B Preferred Stock are not entitled to vote on any matter on which stockholders generally are entitled to vote. In addition, the holders are not entitled to any dividends from the Company other than the right to participate pro rata in any dividends paid on shares of Class A Common Stock on an as-converted basis. The holders of the Series B Preferred Stock are also entitled to receive, after payment or provision for debts and liabilities and prior to any distribution in respect of our Class A Common Stock or any other junior securities, liquidating distributions in an amount equal to $0.0001 per share of Series B Preferred Stock in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.

        Each share of Series B Preferred Stock will automatically convert into 250 shares of Class A Common Stock (as adjusted to account for any stock split, subdivision, exchange or similar reclassification or recapitalization of the outstanding shares of Class A Common Stock into a greater or lesser number of shares) upon the approval of the NASDAQ Proposal.

        In addition, beginning on the third anniversary of the closing of the Silverback Acquisition and issuance of the Series B Preferred Stock to the Riverstone Purchasers, the Series B Preferred Stock will be redeemable by us for a redemption price per share, determined on an as-converted basis, equal to the average of the last reported sale price for a share of Class A Common Stock on the NASDAQ or other domestic securities exchange upon which the shares of Class A Common Stock are then listed for the 10 consecutive trading days prior to the date of redemption or, if such shares are no longer traded on such an exchange, at the fair market value of a share of Class A Common Stock, as determined in good faith by our board of directors.

Interests of Certain Persons in the NASDAQ Proposal

        In considering the recommendation of our board of directors to approve the NASDAQ Proposal, you should be aware that several of our directors, including Mark G. Papa, Robert M. Tichio, David M. Leuschen and Pierre F. Lapeyre, have relationships with Riverstone. As of the record date, Riverstone owned approximately        % of our Class A Common Stock,        % of our voting stock and all of the outstanding shares of Series B Preferred Stock.

        If the NASDAQ Proposal is approved at our special meeting, Riverstone will receive shares of Class A Common Stock upon the automatic conversion of its shares of Series B Preferred Stock. The shares of Class A Common Stock will be listed on the NASDAQ and will therefore be a more liquid security than the shares of Series B Preferred Stock. Our other stockholders will not receive any additional securities or other consideration if the NASDAQ Proposal is approved.

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Effect of Proposal on Current Stockholders

        If the NASDAQ Proposal is approved, 26,100,000 shares of Class A Common Stock will be issued to the Riverstone Purchasers, representing         % of the shares of Common Stock outstanding on the date hereof. The issuance of such shares would result in dilution to the voting power of the holders of our outstanding Common Stock. If the NASDAQ Proposal is not approved at the special meeting or at a subsequent meeting of our stockholders held to approve a similar proposal, the shares of Series B Preferred Stock will not be converted into shares of Class A Common Stock and will remain outstanding in accordance with the terms set forth in the Certificate of Designation.

Vote Required for Approval

        Approval of the NASDAQ Proposal requires the affirmative vote (in person or by proxy) of holders of a majority of the outstanding shares of Class A Common Stock entitled to vote and actually cast thereon at the special meeting. Holders of the shares of Class A Common Stock issued in the Silverback Acquisition Private Placements are not entitled to vote such shares on the NASDAQ Proposal. Failure to vote by proxy or to vote in person at the special meeting or an abstention from voting will have no effect on the outcome of the vote on the NASDAQ Proposal.

        As of the record date, Riverstone held        % of the shares of Common Stock entitled to vote at the special meeting and will be able to control the outcome of the vote on the NASDAQ Proposal. Riverstone has advised the Company that it intends to vote all of the shares of Common Stock held by it in favor of the NASDAQ Proposal at the special meeting.

Recommendation of the Board of Directors

OUR BOARD OF DIRECTORS RECOMMENDS THAT OUR STOCKHOLDERS VOTE "FOR" THE NASDAQ PROPOSAL.

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PROPOSAL NO. 2—THE ADJOURNMENT PROPOSAL

Overview

        The Adjournment Proposal, if adopted, will allow our board of directors to adjourn the special meeting to a later date or dates to permit further solicitation of proxies. The Adjournment Proposal will only be presented to our stockholders in the event that there are insufficient votes for, or otherwise in connection with, the approval of the NASDAQ Proposal.

Consequences if the Adjournment Proposal is Not Approved

        If the Adjournment Proposal is not approved by the Company's stockholders, the board of directors may not be able to adjourn the special meeting to a later date in the event that there are insufficient votes for, or otherwise in connection with, the approval of the NASDAQ Proposal.

Vote Required for Approval

        The approval of the Adjournment Proposal requires the affirmative vote (in person or by proxy) of the holders of a majority of the outstanding shares of Class A Common Stock entitled to vote and actually cast thereon at the special meeting. Failure to vote by proxy or to vote in person at the special meeting or an abstention from voting will have no effect on the outcome of the vote on the Adjournment Proposal.

        As of the record date, Riverstone held        % of the shares of Common Stock entitled to vote at the special meeting and will be able to control the outcome of the vote on the Adjournment Proposal. Riverstone has advised the Company that it intends to vote all of the shares of Common Stock held by it in favor of the Adjournment Proposal at the special meeting.

Recommendation of the Board of Directors

OUR BOARD OF DIRECTORS RECOMMENDS THAT OUR STOCKHOLDERS VOTE "FOR" THE APPROVAL OF THE ADJOURNMENT PROPOSAL.

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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 financial statements and related notes of CRP included elsewhere in this proxy statement. The following discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Actual results and the timing of events may differ materially from those contained 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 proxy statement, 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.

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.

Recent Developments

        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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Market Conditions

        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.

How We Evaluate Our Operations

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

•

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

•

production results;

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•

lease operating expenses; and

•

Adjusted EBITDAX.

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

Sources of Our Revenues

        Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. 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

        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.

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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.

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.

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        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 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

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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.

        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").

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        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	%
Average daily production volume:
Oil (Bbls/d)		5,547		4,868		679			14	%
Natural gas (Mcf/d)		9,310		8,077		1,233			15	%
NGLs (Bbls/d)		883		886		(3	)		—	%
Total (Boe/d)(2)		7,982		7,101		881			12	%

(1)

Average prices shown in the table reflect prices before the effects of our realized commodity derivative transactions.

(2)

Total may not sum or recalculate due to rounding.

        As reflected in the table above, our total revenues for the first nine months of 2016 were 4%, or $3.0 million, lower than total revenues for the first nine months of 2015. The decrease was primarily due to a decrease in commodity prices, resulting in a 15% decrease in average sales price per Boe, which was partially offset by a 13% increase in production sold in the first nine months of 2016 compared to the prior year.

        Oil sales decreased 4%, or $2.1 million, for the first nine months of 2016 compared to the prior year period primarily due to a 16% decrease in the average sales price for oil, partially offset by a 14% increase in oil volumes sold. Natural gas sales decreased 6%, or $0.4 million, for the first nine months of 2016 compared to the prior year period primarily due to a 19% decrease in the average sales price for natural gas, partially offset by a 16% increase in natural gas volumes sold. NGL sales decreased 14%, or $0.5 million, for the first nine months of 2016 compared to the prior year period primarily due to a 14% decrease in the average sales price for NGLs.

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        Operating Expenses.    We present per Boe information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis.

        The following table summarizes our operating expenses for the periods indicated:

	Nine Months Ended September 30,
	2016			2015			Change			% Change
Operating Expenses (in thousands):
Lease operating expenses	$	10,295		$	17,317		$	(7,022	)		(41	)%
Severance and ad valorem taxes		3,523			3,833			(310	)		(8	)%
Transportation, processing, gathering and other operating expense		4,375			4,352			23			1	%
Depreciation, depletion, amortization and accretion of asset retirement obligations		60,939			64,003			(3,064	)		(5	)%
Abandonment expense and impairment of unproved properties		2,546			3,851			(1,305	)		(34	)%
Contract termination and rig stacking		—			2,388			(2,388	)		(100	)%
General and administrative expenses		10,655			8,538			2,117			25	%
Total operating expenses before gain on oil and natural gas properties		92,333			104,282			(11,949	)		(11	)%
Gain on sale of oil and natural gas properties		(11	)		(2,688	)		2,677			(100	)%
Total operating expenses after gain on oil and natural gas properties	$	92,322		$	101,594		$	(9,272	)		(9	)%
Expenses per Boe:
Lease operating expenses	$	4.71		$	8.93		$	(4.22	)		(47	)%
Severance and ad valorem taxes		1.61			1.98			(0.37	)		(19	)%
Transportation, processing, gathering and other operating expense		2.00			2.24			(0.24	)		(11	)%
Depreciation, depletion, amortization and accretion of asset retirement obligations		27.86			33.01			(5.15	)		(16	)%
Abandonment expense and impairment of unproved properties		1.16			1.99			(0.83	)		(42	)%
Contract termination and rig stacking		—			1.23			(1.23	)		(100	)%
General and administrative expenses		4.87			4.40			0.47			11	%
Total operating expenses per Boe	$	42.21		$	53.78		$	(11.57	)		(22	)%

        Lease Operating Expenses.    We experience volatility in our LOE as a result of the impact industry activity has on service provider costs and seasonality in workover expense. LOE decreased 41%, or $7.0 million, in the first nine months of 2016 compared to the first nine months of 2015, due in part to service providers lowering costs in light of the weak commodity price environment. Additionally, we shut in several non-economic wells at the beginning of 2016, which decreased LOE approximately $1.0 million. Workover expense decreased $2.1 million and we converted several rental units to permanent pumping units decreasing the amounts of rental expense by approximately $1.0 million in the first nine months of 2016 compared to the prior year period. Lastly, we decreased the use of contract labor and expenses related to repairs and maintenance by $1.3 million and $1.6 million, respectively, in the first nine months of 2016 compared to the first nine months of 2015.

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        Severance and Ad Valorem Taxes.    Severance taxes are primarily based on the market value of our production at the wellhead and ad valorem taxes are generally based on the valuation of our oil and natural gas properties and vary across the different counties in which we operate. Severance and ad valorem taxes decreased 8%, or $0.3 million, in the first nine months of 2016 compared to the first nine months of 2015, primarily due to lower production revenues, which were primarily a result of lower realized commodity prices. Severance and ad valorem taxes as a percentage of our revenue were 5.4% for the first nine months of 2016 compared to 5.6% for the prior year period.

        Transportation, Processing, Gathering and Other Operating Expenses.    Transportation, processing, gathering and other operating expenses were relatively flat in the first nine months of 2016 compared to the first nine months of 2015.

        Depreciation, Depletion, Amortization and Accretion of Asset Retirement Obligations.    Our DD&A rate can fluctuate as a result of impairments, dispositions, finding and development costs and proved reserve volumes. DD&A decreased 5%, or $3.1 million, in the first nine months of 2016 compared to the first nine months of 2015, primarily due to a decrease in the DD&A rate, partially offset by an increase in average production volumes. The decrease in the DD&A rate was primarily due to lower drilling costs, in conjunction with lower LOE that extends the economic lives of our wells. DD&A per Boe was $27.86 for the first nine months of 2016 compared to $33.01 for the prior year period.

        Abandonment Expense and Impairment of Unproved Properties.    In the nine months ended September 30, 2016 and 2015, we recorded $2.5 million and $3.9 million, respectively, of abandonment expense attributable to leases that expired during the period or that we expect to expire in the future.

        Contract Termination and Rig Stacking.    In the first nine months of 2016, we did not incur any drilling and rig termination fees, as compared to $2.4 million in the first nine months of 2015. In light of the low commodity price environment, we curtailed drilling activity beginning in the first quarter of 2015, and as a result, incurred drilling and rig termination fees of $2.4 million in the first nine months of 2015.

        General and Administrative Expenses.    G&A expenses increased 25%, or $2.1 million, primarily due to an increase in transaction costs and miscellaneous expenses of $1.1 million each in the first nine months of 2016 compared to the first nine months of 2015. G&A per Boe was $4.87 for the first nine months of 2016 compared to $4.40 for the prior year period. The increase in G&A per Boe was primarily due to an increase in expenses, partially offset by an increase in production during the first nine months of 2016 compared to the first nine months of 2015.

        Gain on Sale of Oil and Natural Gas Properties.    In the first nine months of 2016, we recorded an immaterial net gain on the sale of oil and natural gas properties as compared to a net gain of $2.7 million in the prior year period, which was primarily attributable to a gain associated with the sale of non-core unproved property to an unrelated third party.

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

	Nine Months Ended September 30,
	2016			2015			Change			% Change
Other (expense) income (in thousands):
Interest expense	$	(5,422	)	$	(4,743	)	$	(679	)		14	%
Gain (loss) on derivative instruments		(4,184	)		12,320			(16,504	)		(134	)%
Other (expense) income		6			(5	)		11			(220	)%
Total other (expense) income	$	(9,600	)	$	7,572		$	(17,172	)		(227	)%
Income tax (expense) benefit	$	406		$	—		$	406			100	%

        Interest Expense.    Interest expense increased 14%, or $0.7 million, primarily due to an increase in the average borrowings under CRP's revolving credit facility during the first nine months of 2016 compared to the first nine months of 2015.

        Gain on Derivative Instruments.    In the first nine months of 2016, we recognized a $4.2 million derivative loss as compared to a $12.3 million derivative gain in the first nine months of 2015. Net losses and gains on its derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.

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Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014

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

	Year Ended December 31,
	2015		2014		Change			% Change
Revenues (in thousands):
Oil sales	$	77,643	$	114,955	$	(37,312	)		(32	)%
Natural gas sales		7,965		9,670		(1,705	)		(18	)%
NGL sales		4,852		7,200		(2,348	)		(33	)%
Total revenues	$	90,460	$	131,825	$	(41,365	)		(31	)%
Average sales price:(1)
Oil (per Bbl)	$	42.43	$	80.50	$	(38.07	)		(47	)%
Natural gas (per Mcf)		2.60		4.58		(1.98	)		(43	)%
NGLs (per Bbl)		14.66		30.64		(15.98	)		(52	)%
Total (per Boe)	$	33.87	$	65.42	$	(31.55	)		(48	)%
Production:
Oil (MBbls)		1,830		1,428		402			28	%
Natural gas (MMcf)		3,058		2,112		946			45	%
NGLs (MBbls)		331		235		96			41	%
Total (MBoe)(2)		2,671		2,015		656			33	%
Average daily production volumes:
Oil (Bbls/d)		5,014		3,912		1,102			28	%
Natural gas (Mcf/d)		8,378		5,786		2,592			45	%
NGLs (Bbls/d)		907		644		263			41	%
Total (Boe/d)(2)		7,317		5,521		1,796			33	%

(1)

Average prices shown in the table reflect prices before the effects of CRP's realized commodity derivative transactions.

(2)

Totals may not sum or recalculate due to rounding.

        As reflected in the table above, our total revenues for 2015 was 31%, or $41.4 million, lower than in 2014. The decrease was primarily due to a significant decrease in commodity prices, resulting in a 48% decrease in the average sales price per Boe. The decrease was offset in part by a 33% increase in average daily production sold in 2015 compared to 2014. The increase in average daily production in 2015 was negatively impacted by property divestitures that occurred in 2014. In 2014, average daily production attributable to the property dispositions approximated 310 Boe/d.

        Oil sales decreased 32%, or $37.3 million, primarily as result of a 47% decrease in average sales price for oil, offset by a 28% increase in oil volumes sold. Natural gas sales decreased 18%, or $1.7 million, primarily as a result of 43% decrease in the average sales price for natural gas, offset by a 45% increase in natural gas volumes sold. NGL sales decreased 33%, or $2.3 million, primarily as a result of a 52% decrease in the average price for NGLs, offset by a 41% increase in NGL volumes sold.

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

	Year Ended December 31,
	2015			2014		Change			% Change
Operating expenses (in thousands):
Lease operating expenses	$	21,173		$	17,690	$	3,483			20	%
Severance and ad valorem taxes		5,021			6,875		(1,854	)		(27	)%
Transportation, processing, gathering and other operating expenses		5,732			4,772		960			20	%
Depreciation, depletion, amortization and accretion of asset retirement obligations		90,084			69,110		20,974			30	%
Abandonment expense and impairment of unproved properties		7,619			20,025		(12,406	)		(62	)%
Exploration		84			—		84			100	%
Contract termination and rig stacking		2,387			—		2,387			100	%
General and administrative expenses		14,206			31,694		(17,488	)		(55	)%
Total operating expenses	$	146,306		$	150,166	$	(3,860	)		(3	)%
(Gain) loss on sale of oil and natural gas properties		(2,439	)		2,096		NM			NM
Total operating expenses after (gain) loss on sale of oil and natural gas properties	$	143,867		$	152,262	$	(8,395	)		(6	)%
Average unit costs per Boe:
Lease operating expenses	$	7.93		$	8.78	$	(0.85	)		(10	)%
Severance and ad valorem taxes		1.88			3.41		(1.53	)		(45	)%
Transportation, processing, gathering and other operating expenses		2.15			2.37		(0.22	)		(9	)%
Depreciation, depletion, amortization and accretion of asset retirement obligations		33.73			34.30		(0.57	)		(2	)%
Abandonment expense and impairment of unproved properties		2.85			9.94		(7.09	)		(71	)%
Exploration		0.03			—		0.03			100	%
Contract termination and rig stacking		0.89			—		0.89			100	%
General and administrative expenses		5.32			15.73		(10.41	)		(66	)%
Total operating expenses per Boe	$	54.78		$	74.53	$	(19.75	)		(26	)%

        Lease Operating Expenses.    We experience volatility in our LOE as a result of the impact industry activity has on service provider costs and seasonality in workover expense. LOE increased 20%, or $3.5 million, in 2015 as compared to 2014, as we continued to put new wells on production, resulting in increased needs for compression, rental equipment, fuel, saltwater disposal and chemicals. We also had a year-over-year increase in workover expense.

        Severance and Ad Valorem Taxes.    Severance taxes are primarily based on the market value of our production at the wellhead and ad valorem taxes are generally based on the valuation of our oil and natural gas properties and vary across the different counties in which we operate. Severance and ad valorem taxes decreased 27%, primarily due to lower production revenues primarily as a result of lower realized commodity prices. Severance and ad valorem taxes as a percentage of our revenue was 5.6% for 2015 compared to 5.2% for 2014.

        Transportation, Processing, Gathering and Other Operating Expenses.    Transportation, processing, gathering and other operating expenses increased 20%, or $1.0 million. In 2015, lower prices for

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natural gas and NGLs resulted in lower costs associated with fuel and processing fees, which were partially offset by higher processing volumes.

        Depreciation, Depletion, Amortization and Accretion of Asset Retirement Obligations.    Our DD&A rate can fluctuate as a result of impairments, dispositions, finding and development costs and proved reserve volumes. DD&A expense increased 30%, or $21.0 million, primarily due to an increase in production volumes. DD&A per Boe was $33.73 for 2015, a slight decrease as compared to $34.30 in 2014.

        Abandonment Expense and Impairment of Unproved Properties.    In 2015, we recorded $7.6 million attributable to leases that expired during the year or were expected to expire in the future. In 2014, we recorded impairment expense of $20.0 million, of which $13.8 million was attributable to an impairment of unproved properties and $6.2 million was attributable to leases that expired during the year or were expected to expire in the future.

        Contract Termination and Rig Stacking.    In light of the low commodity price environment, we curtailed drilling activity in 2015. As a result, we incurred drilling and rig termination fees of $2.4 million in 2015 as compared to no drilling and rig termination fees in 2014.

        General and Administrative Expenses.    G&A expenses decreased 55%, or $17.5 million, primarily due to $12.4 million of incentive compensation recorded in 2014 due to the achievement of certain performance criteria associated with CRP's incentive units. Additionally, the decrease is the result of no longer having two distinct management teams and employees associated with each of CRP and Celero along with our growing capital program and oil production levels.

        Gain (Loss) on Sale of Oil and Natural Gas Properties.    In 2015, we recorded a net gain of $2.4 million, primarily attributable to the sale of non-core unproved property to an unrelated third party. In 2014, we recorded a net loss of $2.1 million, primarily attributable to the CO2 Project Disposition.

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

	Year Ended December 31,
	2015			2014			Change			% Change
Other income (expense) (in thousands):
Interest expense	$	(6,266	)	$	(2,475	)	$	(3,791	)		153	%
Gain on derivative instruments		20,756			41,943			(21,187	)		(51	)%
Other income		20			281			(261	)		NM
Total other income	$	14,510		$	39,749		$	(25,239	)		(63	)%
Income tax benefit (expense)	$	572		$	(1,524	)		NM			NM

        Interest Expense.    Interest expense increased $3.8 million, or 153%, primarily due to an increase in the average amounts outstanding under our term loan and revolving credit facility in 2015 compared to 2014.

        Gain on Derivative Instruments.    In 2015, we recognized a $20.8 million gain on derivative instruments compared to a $41.9 million gain on derivative instruments in 2014. Net gains on our derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.

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        Income Tax Benefit (Expense).    We are treated as a flow-through entity for U.S. federal income tax purposes and the purposes of certain state and local income taxes and, accordingly, are not subject to such income taxes. We are subject to the Texas franchise tax, at a statutory rate of 0.75% of income. For the year ended December 31, 2015, we recognized a tax benefit of $0.6 million associated with our Texas franchise tax obligation. For the year ended December 31, 2014, we recognized income tax expense of $1.5 million. The decrease was primarily due to a decrease in the Texas franchise tax rate and a decrease in our estimated income attributable to Texas franchise tax year-over-year.

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

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

	Year Ended December 31,
	2014		2013		Change			% Change
Revenues (in thousands):
Oil sales	$	114,955	$	65,863	$	49,092			75	%
Natural gas sales		9,670		3,024		6,646			220	%
NGL sales		7,200		3,087		4,113			133	%
Total revenues	$	131,825	$	71,974	$	59,851			83	%
Realized sales price:
Oil (per Bbl)	$	80.50	$	92.37	$	(11.87	)		(13	)%
Natural gas (per Mcf)		4.58		3.79		0.79			21	%
NGLs (per Bbl)		30.64		31.50		(0.86	)		(3	)%
Total (per Boe)	$	65.42	$	76.24	$	(10.82	)		(14	)%
Production:
Oil (MBbls)		1,428		713		715			100	%
Natural gas (MMcf)		2,112		797		1,315			165	%
NGLs (MBbls)		235		98		137			140	%
Total (MBoe)(1)		2,015		944		1,071			113	%
Average daily production volumes:
Oil (Bbls/d)		3,912		1,953		1,959			100	%
Natural gas (Mcf/d)		5,786		2,184		3,602			165	%
NGLs (Bbls/d)		644		268		376			140	%
Total (Boe/d)(1)		5,521		2,586		2,935			114	%

(1)

Totals may not sum or recalculate due to rounding.

        Oil sales increased 75%, or $49.1 million, primarily as result of a 100% increase in oil volumes sold, partially offset by a 13% decrease in the average realized price in 2014 compared to 2013. Excluding the CO2 Project Disposition and the Wolfbone Disposition, oil production increased 180%, or 876 MBbls, to 1,363 MBbls in 2014 from 487 MBbls in 2013. The increase in production was partially offset by a decrease of 161 MBbls attributable to these dispositions.

        Natural gas sales increased 220%, or $6.6 million, primarily as a result of a 165% increase in natural gas volumes sold and a 21% increase in the average realized price in 2014 compared to 2013. Excluding the CO2 Project Disposition and the Wolfbone Disposition, natural gas production increased 201%, or 1,394 MMcf, to 2,089 MMcf in 2014 from 695 MMcf in 2013. The increase in production was partially offset by a decrease of 79 MMcf attributable to these dispositions.

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        NGL sales increased 133%, or $4.1 million, primarily as a result of a 140% increase in NGL volumes sold, partially offset by a 3% decrease in the average realized price in 2014 compared to 2013. Excluding the CO2 Project Disposition and the Wolfbone Disposition, natural gas production and ultimately the NGLs extracted during processing increased 153%, or 142 MBbls, to 235 MBbls in 2014 from 93 MBbls in 2013. The increase in NGL volumes extracted was partially offset by a decrease of 5 MBbls attributable to the Wolfbone Disposition and the CO2 Project Disposition.

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

	Year Ended December 31,
	2014		2013			Change			% Change
Operating expenses (in thousands):
Lease operating expenses	$	17,690	$	19,106		$	(1,416	)		(7	)%
Severance and ad valorem taxes		6,875		4,153			2,722			66	%
Transportation, processing, gathering and other operating expenses		4,772		1,291			3,481			270	%
Depreciation, depletion, amortization and accretion of asset retirement obligations		69,110		29,285			39,825			136	%
Abandonment expense and impairment of unproved properties		20,025		8,561			11,464			134	%
General and administrative expenses		31,694		16,842			14,852			88	%
Total operating expenses	$	150,166	$	79,238		$	70,928			90	%
Loss (gain) on sale of oil and natural gas properties		2,096		(16,756	)		18,852			NM
Total operating expenses after loss (gain) on sale of oil and natural gas properties	$	152,262	$	62,482		$	89,780			144	%
Average unit costs per Boe:
Lease operating expenses	$	8.78	$	20.24		$	(11.46	)		(57	)%
Severance and ad valorem taxes		3.41		4.40			(0.99	)		(23	)%
Transportation, processing, gathering and other operating expenses		2.37		1.37			1.00			73	%
Depreciation, depletion, amortization and accretion of asset retirement obligations		34.30		31.02			3.28			11	%
Abandonment expense and impairment of unproved properties		9.94		9.07			0.87			10	%
General and administrative expenses		15.73		17.84			(2.11	)		(12	)%
Total operating expenses per Boe	$	74.53	$	83.94		$	(9.41	)		(11	)%

        Lease Operating Expenses.    LOE decreased 7%, or $1.4 million, primarily due to the Wolfbone Disposition and the CO2 Project Disposition, which accounted for $12.5 million of CRP's LOE in 2013 compared to $4.4 million in 2014. The decrease was offset by an increase in costs for compression, rental equipment, fuel and overhead associated with bringing additional wells on production during 2014. LOE per Boe, excluding the Wolfbone Disposition and the CO2 Project Disposition, was $6.84 for the year ended December 31, 2014 compared to $8.22 for the year ended December 31, 2013. The decrease per Boe was primarily related to a 113% increase in production volumes in 2014 compared to 2013.

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        Severance and Ad Valorem Taxes.    Severance taxes are primarily based on the market value of our production at the wellhead and ad valorem taxes are generally based on the valuation of our oil and natural gas properties and vary across the different counties in which we operate. Severance and ad valorem taxes increased 66%, primarily as a result of an 83% increase in revenues. The increase was partially offset by the Wolfbone Disposition and the CO2 Project Disposition, which accounted for $1.6 million of our severance taxes in 2013 compared to $0.5 million in 2014. Severance and ad valorem taxes as a percentage of our revenue was 5.2% for 2014 compared to 5.8% for 2013.

        Transportation, Processing, Gathering and Other Operating Expenses.    Transportation, processing, gathering and other operating expenses increased 270%, or $3.5 million, primarily due to an increase in sales and processing volumes. In 2014, our natural gas and NGL volumes increased 162% compared to 2013. Transportation, processing, gathering and other operating expenses per Boe, excluding the Wolfbone Disposition and the CO2 Project Disposition, was $2.45 for 2014 compared to $1.85 for the year ended December 31, 2013. The increase per Boe was primarily related to an increase in gathering expense in 2014 compared to 2013.

        Depreciation, Depletion, Amortization and Accretion of Asset Retirement Obligations.    Our DD&A rate can fluctuate as a result of impairments, dispositions and changes in the mix of our production and the underlying proved reserve volumes. DD&A expense increased 136%, or $39.8 million, primarily due to a 113% increase in production volumes. DD&A, excluding the Wolfbone Disposition and the CO2 Project Disposition, was $67.6 million, or $34.75 per Boe, in 2014 compared to $21.7 million, or $31.17 Boe, in 2013. DD&A per Boe primarily increased as we continued to shift toward drilling more horizontal wells, which are comparatively more expensive than vertical wells. DD&A expense, excluding our dispositions, increased due to the aforementioned increase in production on our properties.

        General and Administrative Expenses.    G&A expenses increased 88%, primarily due to $12.4 million of incentive compensation recorded in 2014 due to the achievement of certain performance criteria associated with our incentive units. Additionally, the increase was the result of having two distinct management teams and employees associated with CRP's predecessors along with its growing capital program and oil production levels.

        Loss (Gain) on Sale of Oil and Natural Gas Properties.    We recorded a loss on sale of assets of $2.1 million in 2014 and a gain on sale of assets of $16.8 million in 2013. The loss in 2014 and gains in 2013 were primarily attributable to the following:

•

In May 2014, we completed the CO2 Project Disposition for net cash proceeds of approximately $60 million and realized a loss on sale of $1.8 million.

•

In October 2013, we completed the Wolfbone Disposition for total proceeds of approximately $28.7 million and realized a gain on sale of $7.7 million.

•

In August 2013, we sold oil and natural gas properties in the Midland Basin for total proceeds of $17.1 million and realized a $7.9 million gain on sale.

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

	Year Ended December 31,
	2014			2013			Change			% Change
Other income (expense) (in thousands):
Interest expense	$	(2,475	)	$	(513	)	$	(1,962	)		382	%
Gain (loss) on derivative instruments		41,943			(4,410	)		46,353			NM
Other expense		281			122			159			130	%
Total other income (expense)	$	39,749		$	(4,801	)	$	44,550			NM
Income tax expense	$	(1,524	)	$	(1,079	)	$	(445	)		41	%

        Interest Expense.    Interest expense increased $2.0 million, or 382%, primarily due to an increase in the borrowings under CRP's revolving credit facility during 2014 as compared to 2013 as well as due to the interest associated with CRP's term loan, which was entered into in the fourth quarter of 2014.

        Gain (Loss) on Derivative Instruments.    During 2014, we recognized a $41.9 million gain on derivative instruments compared to a $4.4 million loss on derivative instruments in 2013, primarily as a result of the impact of changing commodity prices on increased hedging activities.

        Income Tax Expense.    During the year ended December 31, 2014, we recognized $1.5 million of expense associated with our Texas franchise tax obligation, an increase of $0.4 million, or 41%, as compared to the $1.1 million we recognized during the year ended December 31, 2013. The increase was based on an increase in our estimated taxable income subject to Texas franchise tax year-over-year.

Capital Requirements and Sources of Liquidity

        Our development and acquisition activities require us to make significant operating and capital expenditures. Historically, our primary sources of liquidity have been capital contributions from CRP's equity sponsors, borrowings under CRP's revolving credit facility and term loan, proceeds from asset dispositions and cash flows from operations. CRD and NGP Follow-On, CRP's equity sponsors, agreed to make capital contributions to CRP of up to $321.9 million and $184.5 million, respectively, and as of September 30, 2016, CRD and NGP Follow-On have made total capital contributions of $289.4 million and $84.2 million, respectively. To date, our primary use of capital has been for the development and acquisition of oil and natural gas properties.

        We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we expect to maintain an active hedging program that seeks to reduce our exposure to commodity prices and protect our cash flow.

        The amount and allocation of future capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing and financing activities, and our ability to assimilate acquisitions and execute our drilling program. We periodically review our capital expenditure budget to assess changes in current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

        Our 2016 capital budget for drilling, completion and recompletion activities and facilities costs was approximately $92 million, excluding leasing and other acquisitions. In the nine months ended

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September 30, 2016, we incurred capital costs of approximately $48.9 million, excluding leasing and acquisition costs.

        Because we are the operator of a high percentage of our acreage, the amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations. See "Business—Oil and Natural Gas Production Prices and Costs—Developed and Undeveloped Acreage." In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

        As of September 30, 2016, there was $124.0 million outstanding under CRP's revolving credit facility and $0.5 million of letters of credit outstanding, and CRP was able to incur approximately $15.5 million of additional indebtedness under its revolving credit facility. The borrowing base under CRP's revolving credit facility was $140.0 million as of September 30, 2016. In connection with the closing of the Business Combination, CRP repaid all amounts outstanding under its revolving credit facility and term loan and entered into an amendment to its credit agreement to, among other things, increase the borrowing base from $140 million to $200 million. 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.

        Based upon current oil and natural gas price expectations for 2017, we believe that our cash flow from operations and additional borrowings under CRP's revolving credit facility will provide us with sufficient liquidity to execute our current capital program. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot ensure that operations and other needed capital will be available on acceptable terms or at all. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot ensure that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.

Working Capital

        We define working capital as current assets minus current liabilities. At September 30, 2016, we had a working capital deficit of $11.6 million. At December 31, 2015, we had working capital of $12.0 million, and at December 31, 2014, we had a working capital deficit of $36.2 million. We may continue to incur working capital deficits in the future due to the amounts that accrue related to our drilling program. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash and cash equivalents balance totaled $0.4 million, $1.8 million and $13.0 million at September 30, 2016, December 31, 2015 and

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December 31, 2014, respectively. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

Cash Flows

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

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

Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2016 and September 30, 2015

        Operating Activities.    Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs, production volumes and changes in working capital. The increase in net cash provided by operating activities for the first nine months of 2016 compared to the first nine months of 2015 was primarily due to a $11.9 million reduction in operating expenses and a positive cash flow impact from working capital of $8.4 million, partially offset by a $3.0 million decrease in total revenues and a $9.3 million decrease in derivatives settlements.

        Investing Activities.    Net cash used in investing activities is primarily comprised of acquisition and development of oil and natural gas properties, net of dispositions. In the first nine months of 2016, net cash used for investing activities included $100.8 million attributable to the acquisition and development of oil and natural gas properties. In the first nine months of 2015, net cash used for investing activities included $171.9 million attributable to the acquisition and development of oil and natural gas properties.

        Financing Activities.    Net cash provided by financing activities in the first nine months of 2016 included $55.0 million of borrowings under CRP's revolving credit facility, offset by repayments of $5.0 million. Net cash provided by financing activities in the first nine months of 2015 included $110.7 million of capital contributions, which were primarily used to repay a portion of CRP's revolving credit facility.

Analysis of Cash Flow Changes Between the Year Ended December 31, 2015 and 2014

        Operating Activities.    Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs, production volumes and changes in working capital. The decrease in net cash provided by operating activities for the year ended December 31, 2015 as compared to the prior year is primarily due to a $41.4 million decrease in total revenues and a decrease in changes in current assets and current liabilities, which decreased cash proceeds provided by operating activities by $16.4 million. The decreases are primarily offset by an increase in net cash received for derivative settlements of $30.9 million.

        Investing Activities.    Net cash used in investing activities is primarily comprised of acquisition and development of oil and natural gas properties net of dispositions. In 2015, net cash used for investing activities included $201.3 million attributable to the acquisition and development of oil and natural gas properties, offset by proceeds from asset sales of $2.7 million. In 2014, net cash used for investing

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activities included $298.3 million attributable to the acquisition and development of oil and natural gas properties, offset by net proceeds from asset sales of $129.9 million.

        Financing Activities.    Net cash provided by financing activities in 2015 included $92.0 million of borrowings under CRP's revolving credit facility, offset by repayments of $83.0 million, capital contributions of $111.4 million, $1.6 million of payments associated with our financing obligation and debt issuance costs of $0.3 million. Net cash provided by financing activities in 2014 included $196.0 million of borrowing under CRP's revolving credit facility, offset by $160.0 million of repayments, $65.0 million of proceeds from CRP's term loan, and capital contributions of $59.8 million, offset by $119.3 million attributable to the repurchase of equity interests and $1.6 million of debt issuance costs.

Analysis of Cash Flow Changes Between the Year Ended December 31, 2014 and 2013

        Operating Activities.    Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs, production volumes and changes in working capital. The increase in net cash provided by operating activities for the year ended December 31, 2014 as compared to the prior year was primarily due to a $59.9 million increase in total revenues and an increase in changes in current assets and current liabilities which increased cash proceeds by operating activities by $16.5 million.

        Investing Activities.    Net cash used in investing activities is primarily comprised of acquisition and development of oil and natural gas properties net of dispositions. The increase in cash used in investing activities for the year ended December 31, 2014 as compared to the prior year was primarily due to a $129.0 million increase in capital expenditures attributable to the acquisition and development of oil and natural gas properties, offset by cash proceeds of $71.8 million attributable to the disposition of CRP's midstream assets in 2014.

        Financing Activities.    Net cash provided by financing activities in 2014 included $196.0 million of borrowing under CRP's revolving credit facility, offset by $160.0 million of repayments, $65.0 million of proceeds from CRP's term loan, and capital contributions of $59.8 million, offset by $119.3 million attributable to the repurchase of equity interests. Net cash provided by financing activities in 2013 including $57.0 million of borrowing under CRP's revolving credit facility offset by repayment of $28.0 million, capital contributions of $114.8 million, offset by $21.1 million of capital distributions.

CRP's Term Loan and Its Revolving Credit Facility

        On October 15, 2014, CRP entered into an amended and restated credit agreement (as amended, the "credit agreement") with JPMorgan Chase Bank, N.A., as administrative agent, and a syndicate of lenders, that includes both a term loan commitment of $65.0 million (the "term loan"), which was fully funded as of September 30, 2016, and a revolving credit facility (the "revolving credit facility") with commitments of $500.0 million (subject to the borrowing base), with a sublimit for letters of credit of $15.0 million. As of September 30, 2016, CRP had $124.0 million outstanding under its revolving credit facility and $0.5 million of letters of credit outstanding, and CRP was able to incur approximately $15.5 million of additional indebtedness under its revolving credit facility. CRP's term loan matures on April 15, 2018, and its revolving credit facility matures on October 15, 2019.

        On October 11, 2016, CRP entered into an amendment to the credit agreement to, among other things, (i) permit the Business Combination, (ii) reflect the repayment in full of all term loans thereunder, (iii) increase the borrowing base from $140.0 million to $200.0 million, (iv) increase the interest rate to LIBOR plus 2.25%-3.25%, and (v) require CRP to have sufficient liquidity and satisfy a maximum leverage ratio in order to make dividends. On December 28, 2016, in connection with the

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closing of the Silverback Acquisition, CRP entered into an amendment to the credit agreement to, among other things, further increase the borrowing base from $200.0 million to $250.0 million.

        The amount available to be borrowed under CRP's revolving credit facility is subject to a borrowing base that will be redetermined semiannually each April 1 and October 1 by the lenders in their sole discretion. CRP's credit agreement also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the volumes of CRP's proved oil and natural gas reserves and estimated cash flows from these reserves and its commodity hedge positions. 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. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under its credit agreement. The next regular redetermination date is scheduled for the spring of 2017.

        Principal amounts borrowed are payable on the term loan maturity date and the revolving credit maturity date, as applicable. Interest on the term loan is LIBOR plus 5.25%. At September 30, 2016, the weighted average interest rate on CRP's term loan was 5.78%. Loans under its revolving credit facility may be base rate loans or LIBOR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for LIBOR loans. LIBOR loans bear interest at LIBOR (adjusted for statutory reserve requirements) plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank's prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of the borrowing base utilized. At September 30, 2016, the weighted average interest rate on borrowings under CRP's revolving credit facility was approximately 2.78%. CRP also pays a commitment fee on unused amounts of its revolving credit facility ranging from 37.5 basis points to 50 basis points, depending on the percentage of the borrowing base utilized. CRP may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

        CRP's credit agreement contains restrictive covenants that limit its ability to, among other things:

•

incur additional indebtedness;

•

make investments and loans;

•

enter into mergers;

•

make or declare dividends;

•

enter into commodity hedges exceeding a specified percentage of its expected production;

•

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

•

incur liens;

•

sell assets; and

•

engage in transactions with affiliates.

        CRP's credit agreement also requires it to maintain compliance with the following financial ratios:

•

a current ratio, which is the ratio of CRP's consolidated current assets (including unused commitments under CRP's revolving credit facility and excluding non-cash assets under Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 815, Derivatives and Hedging and certain restricted cash) to consolidated current liabilities (excluding

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the current portion of long-term debt under its credit agreement and non-cash liabilities under ASC 815), of not less than 1.0 to 1.0; and

•

a leverage ratio, which is the ratio of Total Funded Debt (as defined in CRP's credit agreement) to consolidated EBITDAX (as defined in CRP's credit agreement) for the rolling four fiscal quarter period ending on such day, of not greater than 4.0 to 1.0.

        As of September 30, 2016, CRP was in compliance with such covenants and the financial ratios described above.

Contractual Obligations

        A summary of our contractual obligations as of December 31, 2015 is provided in the following table.

	Payments Due by Period For the Year Ending December 31,
	2016		2017		2018		2019		2020		Thereafter		Total
	(in thousands)
Revolving credit facility(1)	$	—	$	—	$	—	$	74,000	$	—	$	—	$	74,000
Term loan		—		—		65,000		—		—		—		65,000
Drilling rig commitments		422		—		—		—		—		—		422
Office and equipment leases		539		477		485		419		—		—		1,920
Pipeline financing obligation(2)		2,137				—		—		—		—		2,137
Asset retirement obligations(3)		—		—		—		—		—		2,288		2,288
Total	$	3,098	$	477	$	65,485	$	74,419	$	—	$	2,288	$	145,767

(1)

This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on CRP's revolving credit facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. As of September 30, 2016, CRP had $124.0 million outstanding under its revolving credit facility and $0.5 million of letters of credit outstanding, and it was able to incur approximately $15.5 million of additional indebtedness under its revolving credit facility.

(2)

A subsidiary of EagleClaw Midstream Ventures, LLC has constructed an expansion of a gas gathering system for which we have agreed to repay all construction costs, which totaled approximately $4.0 million. Each month, we pay a minimum fee of $7,000 per day until all construction costs are paid.

(3)

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

Quantitative and Qualitative Disclosures About Market Risk

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

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Commodity Price Risk

        Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLs production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. During the period from January 1, 2014 through November 1, 2016, the WTI spot price has declined from a high of $107.62 per Bbl on July 23, 2014 to $26.21 per Bbl on February 11, 2016. NGL prices generally correlate to the price of oil, and accordingly prices for these products have likewise declined and are likely to continue following that market. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and 2016. During the period from January 1, 2014 through November 1, 2016, natural gas prices have 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.

        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 first nine months of 2016. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.3 million change in natural gas revenues for the first nine months of 2016. A $1.00 per barrel change in our realized NGL prices would have resulted in a $0.2 million change in NGL revenues for the first nine months of 2016. Oil sales contributed 87% of our total revenues for the first nine months of 2016. Natural gas sales contributed 9% and NGL sales contributed 5% of our total revenues for the first nine months of 2016. Our oil, natural gas and NGL revenues do not include the effects of derivatives.

        Due to this volatility, we have historically used, and we expect to continue to use, commodity derivative instruments, such as collars, swaps and basis swaps, to hedge price risk associated with a portion of its 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. CRP's credit agreement limits its ability to enter into commodity hedges covering greater than 80% of its reasonably anticipated projected production volume.

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        Our open positions as of September 30, 2016:

Description & Production Period	Volume (Bbl)		Weighted Average Swap Price ($/Bbl)(1)
Crude Oil Swaps:
October 2016 - December 2016		11,500	$	76.25
October 2016 - December 2016		23,000		62.42
October 2016 - December 2016		11,500		77.32
October 2016 - December 2016		23,000		65.58
October 2016 - December 2016		9,200		54.00
October 2016 - December 2016		9,200		53.23
October 2016 - December 2016		9,200		51.80
October 2016 - December 2016		32,200		52.10
October 2016 - December 2016		9,200		50.20
October 2016 - December 2016		9,200		40.87
October 2016 - December 2016		18,400		43.35
October 2016 - December 2016		27,600		42.75
January 2017 - December 2017		91,250		64.05
January 2017 - December 2017		36,500		54.65
January 2017 - December 2017		36,500		43.50
January 2017 - December 2017		36,500		44.85
January 2017 - December 2017		36,500		45.10
January 2017 - December 2017		109,500		44.80
January 2017 - December 2017		36,500		47.27
January 2017 - December 2017		36,500		49.00
January 2017 - December 2017		182,500		49.80
January 2017 - December 2017		73,000		52.35
January 2018 - December 2018		36,500		55.95
Crude Oil Basis Swaps:
August 2016 - November 2016		23,000	$	(1.65	)
August 2016 - November 2016		23,000		(1.05	)
August 2016 - November 2016		23,000		(1.40	)
August 2016 - November 2016		30,500		(0.55	)
August 2016 - November 2016		27,600		0.25
August 2016 - November 2016		18,400		(0.16	)
August 2016 - November 2016		9,200		(0.50	)
August 2016 - November 2016		9,200		(0.40	)
August 2016 - November 2016		27,600		(0.25	)
August 2016 - November 2016		46,000		(0.25	)
August 2016 - November 2016		46,000		(0.20	)
August 2016 - November 2016		18,400		(0.10	)
August 2016 - November 2016		18,400		0.10
November 2016 - November 2017		91,250		(0.20	)
November 2016 - November 2017		36,500		(0.20	)

(1)

The oil swap contracts are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis derivative contracts are settled based on the month's average daily implied principal components of our cost structure.

Description & Production Period	Volume (MMBtu)		Weighted Average Swap Price ($/MMbtu)(1)
Natural Gas Swaps:
January 2017 - December 2017		1,460,000	$	2.94

(1)

The natural gas derivative contracts are settled based on the month's average daily NYMEX price of Henry Hub Natural Gas.

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Counterparty and Customer Credit Risk

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

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

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

Interest Rate Risk

        At September 30, 2016, CRP had $189.0 million of debt outstanding, with an assumed weighted average interest rate of 3.81%. Interest is calculated under the terms of CRP's credit agreement based on a LIBOR spread. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate would be approximately $1.9 million per year. CRP does not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to its outstanding indebtedness.

Critical Accounting Policies and Estimates

        The discussion and analysis of our financial condition and results of operations are based upon consolidated and combined financial statements, which have been prepared in accordance with GAAP. The preparation of the financial statements requires it to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Successful Efforts Method of Accounting for Oil and Natural Gas Activities

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

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

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

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        Exploration Costs.    Exploration costs, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic expenditures, other geological and geophysical costs, and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense.

Impairment of Oil and Natural Gas Properties

        Our proved oil and natural gas properties are recorded at cost. We evaluate our proved properties for impairment when events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and natural gas properties and compare these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future operating and capital expenditures, and discount rates.

        Unproved properties costs consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. We evaluate significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.

Oil and Natural Gas Reserve Quantities

        Our estimated proved reserve quantities and future net cash flows are critical to the understanding of the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our financial statements, including the calculations of depletion and impairment of proved oil and natural gas properties. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure calculations require a 10% discount rate to be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. We engage Netherland, Sewell & Associates, Inc., our independent petroleum engineer ("NSAI"), to prepare our total calculated proved reserve PV-10. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves each year-end. For purposes of depletion and impairment, reserve quantities are adjusted in accordance with GAAP for the impact of additions and dispositions.

Revenue Recognition

        Our revenue recognition policy is significant because revenue is a key component of our results of operations and our forward-looking statements contained in the above analysis of liquidity and capital resources. We derive our revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when our production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month, we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our properties, contractual arrangements, NYMEX and local spot market

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prices and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are recorded in the month payment is received.

Derivative Instruments

        We utilize commodity derivative instruments, including swaps, collars and basis swaps, to manage the price risk associated with the forecasted sale of our oil and natural gas production. Our derivative instruments are not designated as hedges for accounting purposes. Accordingly, changes in fair value are recognized in our consolidated and combined statements of operations in the period of change. Gains and losses on derivatives and premiums paid for put options are included in cash flows from operating activities.

Asset Retirement Obligations

        Our asset retirement obligation represents the estimated present value of the amount we will incur to retire long-lived assets at the end of their productive lives, in accordance with applicable state laws. Our asset retirement obligation is determined by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of inception with an offsetting increase in the carrying amount of the related long-lived asset. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset.

        Asset retirement liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of assets and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the subjectivity of assumptions, the costs to ultimately retire our wells may vary significantly from prior estimates.

Recently Issued Accounting Pronouncements

        In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The new standard becomes effective for us on January 1, 2018, with early adoption is permitted. We are evaluating the impact, if any, that the adoption of this update will have on our condensed consolidated financial statements and related disclosures.

        In February 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-02, Leases, which requires all leasing arrangements to be presented in the balance sheet as liabilities along with a corresponding asset. The ASU will replace most existing leases guidance in GAAP when it becomes effective. The new standard becomes effective for us on January 1, 2019. Although early application is permitted, we do not plan to early adopt the ASU. The standard requires the use of the modified retrospective transition method. We are evaluating the impact, if any, that the adoption of this update will have on our condensed consolidated financial statements and related disclosures.

        In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in financial statements. This amendment will be effected prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. We are evaluating the impact, if any, that the adoption of this update will have on our condensed consolidated financial statements and related disclosures.

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        In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This guidance is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance. In August 2015, the FASB deferred the effective date of the new revenue recognition standard by one year. The revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. We are evaluating the impact, if any, that the adoption of this update will have on our consolidated and combined financial statements and related disclosures.

Internal Controls and Procedures

        We qualify as an "emerging growth company" as defined in the JOBS Act and, as such, we qualify for an exception to the SEC's rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose.

Inflation

        Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2015, 2014 or 2013. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

        We do not currently have any off-balance sheet arrangements.

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BENEFICIAL OWNERSHIP OF SECURITIES

        The following table sets forth information known to the Company regarding the beneficial ownership of our voting common stock as of the record date:

•

each person who is the beneficial owner of more than 5% of the outstanding shares of our voting common stock;

•

each of our named executive officers and directors; and

•

all of our current executive officers and directors, as a group.

        Beneficial ownership is determined according to the rules of the SEC, which generally provide that a person has beneficial ownership of a security if he, she or it possesses sole or shared voting or investment power over that security, including options and warrants that are currently exercisable or exercisable within 60 days.

        The beneficial ownership of our voting Common Stock as of the record date and prior to the conversion of the shares of Series B Preferred Stock is based on 200,868,700 shares of Class A Common Stock, 19,155,921 shares of Class C Common Stock and Warrants to purchase 24,666,643 shares of Class A Common Stock issued and outstanding in the aggregate as of                     , 2017.

        The expected beneficial ownership of our voting Common Stock following the conversion of the shares of Series B Preferred Stock is based on 226,968,700 shares of Class A Common Stock, 19,155,921 shares of Class C Common Stock and Warrants to purchase 24,666,643 shares of Class A Common Stock expected to be issued and outstanding.

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        Unless otherwise indicated, we believe that all persons named in the table below have sole voting and investment power with respect to all shares of voting common stock beneficially owned by them.

	Shares of Common Stock Owned Prior to Conversion of Series B Preferred Stock					Shares of Series B Preferred Stock		Shares of Common Stock Owned After Conversion of Series B Preferred Stock
Name of Beneficial Owner	Number		Percentage			Number		Number		Percentage
5% or Greater Stockholders
Funds affiliated with Riverstone Holdings(1)		104,858,590		50.2	%		104,400		130,958,590		55.7	%
Centennial Resource Development, LLC(2)		12,227,062		5.7	%		—		12,227,062		5.1	%
Celero Energy Company, LP(3)		4,246,898		2.1	%		—		4,246,898		1.8	%
NGP Centennial Follow-On LLC(4)		2,681,961		1.3	%		—		2,681,961		1.2	%
Funds advised by Capital Research and Management Company(5)		16,255,129		8.1	%		—		16,255,129		7.2	%
Fidelity Contrafund: Fidelity Advisor Series Opportunistic Insights Fund(6)(7)		59,000		*			—		59,000		*
Fidelity Contrafund: Fidelity Contrafund(6)(7)		7,528,926		3.7	%		—		7,528,926		3.3	%
Fidelity Contrafund Commingled Pool(6)		774,600		*			—		774,600		*
Fidelity Contrafund: Fidelity Advisor New Insights Fund(6)(7)		1,779,900		*			—		1,779,900		*
Fidelity Contrafund: Fidelity Series Opportunistic Insights Fund(6)(7)		408,700		*			—		408,700		*
Variable Insurance Products Fund III: Balanced Portfolio(6)(7)		187,300		*			—		187,300		*
Fidelity Puritan Trust: Fidelity Balanced Fund(6)(7)		1,735,600		*			—		1,735,600		*
Variable Insurance Products Fund II: Contrafund Portfolio(6)(7)		1,049,900		*			—		1,049,900		*
Fidelity Advisor Series I: Fidelity Advisor Balanced Fund(6)(7)		139,200		*			—		139,200		*
Fidelity Select Portfolios: Energy Portfolio(6)(7)		115,200		*			—		115,200		*
Variable Insurance Products Fund IV: Energy Portfolio(6)(7)		14,400		*			—		14,400		*
Fidelity Central Investment Portfolios LLC: Fidelity Energy Central Fund(6)(7)		45,400		*			—		45,400		*
Fidelity Advisor Series VII: Fidelity Advisor Energy Fund(6)(7)		45,200		*			—		45,200		*
Fidelity Select Portfolios: Natural Resources Portfolio(6)(7)		38,300		*			—		38,300		*
Directors and Named Executive Officers
Mark G. Papa		10,000		*			—		10,000		*
George S. Glyphis		—		—			—		—		—
Sean R. Smith		—		—			—		—		—
Jeffrey H. Tepper(8)		51,218		*			—		51,218		*
Tony R. Weber		—		—			—		—		—
Robert M. Tichio		—		—			—		—		—
David M. Leuschen(1)		104,858,590		50.2	%		104,400		130,958,590		55.7	%
Pierre F. Lapeyre Jr.(1)		104,858,590		50.2	%		104,400		130,958,590		55.7	%
Maire A. Baldwin(8)		11,218		*			—		11,218		*
Karl E. Bandtel(8)		11,218		*			—		11,218		*
All directors and executive officers, as a group(8) (10 individuals)		104,942,244		50.2	%		104,400		131,042,244		55.7	%

*

Less than one percent.

(1)

Includes 61,743,780 shares of Class A Common Stock and 76,304 shares of Series B Preferred Stock held of record by Riverstone VI Centennial QB Holdings, L.P. ("Riverstone QB Holdings), 18,250,421 shares of Class A Common Stock and 22,554 shares of Series B Preferred Stock held of record by REL US Centennial Holdings, LLC ("REL US"), 4,484,389 shares of Class A Common Stock and 5,542 shares of Series B Preferred Stock held of record by Riverstone Non-ECI USRPI AIV, L.P. ("Riverstone Non-ECI") and 12,380,000 shares of Class A Common Stock and warrants to purchase an additional 8,000,000 shares of Class A Common Stock held of record by Silver Run Sponsor, LLC ("Silver Run Sponsor"). David Leuschen and Pierre F. Lapeyre, Jr. are the managing directors of Riverstone Holdings LLC. Riverstone Holdings, LLC is the sole shareholder of Riverstone Energy GP VI Corp.,

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which is the managing member of Riverstone Energy GP VI, LLC, which is the general partner of Riverstone Energy Partners VI, L.P., which is the general partner of Riverstone QB Holdings. Riverstone Energy Partners GP VI, LLC is managed by a six person managing committee consisting of Pierre F. Lapeyre, Jr., David M. Leuschen, James T. Hackett, Michael B. Hoffman, N. John Lancaster and, on a rotating basis, one of E. Bartow Jones, Baran Tekkora and Robert M. Tichio. As such, each of Riverstone Energy Partners GP VI, LLC, Riverstone Energy Partners VI, L.P., Riverstone Energy GP VI Corp., Riverstone Holdings LLC, Mr.Leuschen and Mr. Lapeyre may be deemed to share beneficial ownership of the securities held directly by Riverstone QB Holdings. Riverstone Holdings II (Cayman) Ltd. is the general partner of Riverstone Energy Limited Investment Holdings, LP, which is the sole shareholder of REL IP General Partner Limited, which is the general partner of REL IP General Partner LP, which is the managing member of REL US. Mr. Leuschen and Mr. Lapeyre are the sole shareholders of Riverstone Holdings II (Cayman) Ltd. and have or share voting and investment discretion with respect to the securities held of record by REL US Centennial Holdings, LLC. As such, each of REL IP General Partner LP, REL IP General Partner Limited, Riverstone Energy Limited Investment Holdings, LP, Riverstone Holdings II (Cayman) Ltd., Mr. Leuschen and Mr. Lapeyre may be deemed to have or share beneficial ownership of the securities held directly by REL US. Riverstone Non-ECI GP Ltd. is the sole member of Riverstone Non-ECI Partners GP Cayman LLC, which is the general partner of Riverstone Non-ECI Partners GP (Cayman), L.P., which is the sole member of Riverstone Non-ECI USRPI AIV GP, L.L.C., which is the general partner of Riverstone Non-ECI. Riverstone Non-ECI GP Ltd. is managed by Mr. Leuschen and Mr. Lapeyre, who have or share voting and investment discretion with respect to the securities held of record by Riverstone Non-ECI. As such, each of Riverstone Non-ECI USRPI AIV GP, L.L.C., Riverstone Non-ECI Partners GP (Cayman), L.P., Riverstone Non-ECI Partners GP Cayman LLC, Riverstone Non-ECI GP Ltd., Mr. Leuschen and Mr. Lapeyre may be deemed to have or share beneficial ownership of the securities held directly by Riverstone Non-ECI. Silver Run Sponsor Manager, LLC is the managing member of Silver Run Sponsor. Riverstone Holdings LLC is the managing member of Silver Run Sponsor Manager, LLC. As such, each of Silver Run Sponsor Manager, LLC, Riverstone Holdings LLC, Mr. Leuschen and Mr. Lapeyre may be deemed to share beneficial ownership of the common stock held directly by Silver Run Sponsor, LLC. Each such entity or person disclaims any such beneficial ownership of such securities. The business address for Silver Run Sponsor and Silver Run Sponsor Manager, LLC is 1000 Louisiana Street, Suite 1450, Houston, Texas 77002. The business address for each other person named in this footnote is c/o Riverstone Holdings, 712 Fifth Avenue, 36th Floor, New York, NY 10019.

(2)

The board of managers of CRD has voting and dispositive power over these shares. The board of managers of CRD consists of Ward Polzin, Bret Siepman, Chris Carter, David Hayes, Martin Sumner, Christopher Ray and Tony R. Weber. None of such persons individually have voting and dispositive power over these shares, and the board of managers of CRD acts by majority vote and thus each such person is not deemed to beneficially own the shares held by CRD. NGP X US Holdings, L.P. ("NGP X US Holdings") owns approximately 86% of CRD, and certain members of CRD's management team own approximately 14%. Certain members of CRD's management team and certain of CRD's employees also own incentive units in CRD. Please see the section of the registration statement entitled "Executive Compensation—Narrative Disclosures—Incentive Units" for more information on the incentive units. As a result, NGP X US Holdings may be deemed to indirectly beneficially own the shares held by CRD. NGP X US Holdings disclaims beneficial ownership of these shares except to the extent of its pecuniary interest therein. NGP X Holdings GP, L.L.C. (the sole general partner of NGP X US Holdings), NGP Natural Resources X, L.P. (the sole member of NGP X Holdings GP, L.L.C.), G.F.W. Energy X, L.P. (the sole general partner of NGP Natural Resources X, L.P.) and GFW X, L.L.C. (the sole general partner of G.F.W. Energy X, L.P.) may each be deemed to share voting and dispositive power over the reported shares and therefore may also be deemed to be the beneficial owner of these shares. GFW X, L.L.C. has delegated full power and authority to manage NGP X US Holdings to NGP Energy Capital Management, L.L.C. and accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Chris Carter and Tony R. Weber, both of whom are members of CRD's board of directors, are managing partners of NGP Energy Capital Management, L.L.C. In addition, Craig Glick and Christopher Ray are members of the executive committee of NGP Energy Capital Management, L.L.C. Although none of Messrs. Carter, Weber, Glick or Ray individually have voting or dispositive power over these shares, such individuals may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Each of Messrs. Carter, Weber, Glick and Ray disclaim beneficial ownership of these shares except to the extent of their respective pecuniary interest therein.

(3)

Celero Energy Management, LLC, the general partner of Celero ("Celero GP"), has voting and dispositive power over these shares. The board of managers of Celero GP consists of David Hayes, Bruce Selkirk and Christopher Ray. None of such persons individually have voting and dispositive power over these shares, and the board of managers of Celero GP acts by majority vote and thus each such person is not deemed to beneficially own the shares held by Celero GP. Natural Gas Partners VIII, L.P. ("NGP VIII") owns 94.7% of the membership interests of Celero GP, and the remaining 5.3% is held by certain members of Celero's management team and other minority owners. As a result, NGP VIII may be deemed to indirectly beneficially own these shares. NGP VIII disclaims beneficial ownership of these shares except to the extent of its pecuniary interest therein. G.F.W. Energy VIII, L.P. (the sole general partner of NGP VIII) and GFW VIII, L.L.C. (the sole general partner of G.F.W. Energy VIII, L.P.) may each be deemed to share voting and dispositive power over these shares and therefore may

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also be deemed to be the beneficial owner of these shares. GFW VIII, L.L.C. has delegated full power and authority to manage NGP VIII to NGP Energy Capital Management, L.L.C. and accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Chris Carter and Tony R. Weber (one of our directors) are managing partners of NGP Energy Capital Management, L.L.C. In addition, Craig Glick and Christopher Ray are members of the executive committee of NGP Energy Capital Management, L.L.C. Although none of Messrs. Carter, Weber, Glick or Ray individually have voting or dispositive power over these shares, such individuals may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Each of Messrs. Carter, Weber, Glick and Ray disclaim beneficial ownership of these shares except to the extent of their respective pecuniary interest therein.

(4)

NGP Centennial Follow-On LLC is managed by its managing member, NGP X US Holdings. As such, NGP X US Holdings has voting and dispositive power over these shares. NGP X US Holdings disclaims beneficial ownership of these shares except to the extent of its pecuniary interest therein. NGP X Holdings GP, L.L.C. (the sole general partner of NGP X US Holdings), NGP Natural Resources X, L.P. (the sole member of NGP X Holdings GP, L.L.C.), G.F.W. Energy X, L.P. (the sole general partner of NGP Natural Resources X, L.P.) and GFW X, L.L.C. (the sole general partner of G.F.W. Energy X, L.P.) may each be deemed to share voting and dispositive power over the reported shares and therefore may also be deemed to be the beneficial owner of these shares. G.F.W. Energy X, L.P. has delegated full power and authority to manage NGP Natural Resources X, L.P. to NGP Energy Capital Management, L.L.C. and accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Chris Carter and Tony R. Weber (one of our directors) are managing partners of NGP Energy Capital Management, L.L.C. In addition, Craig Glick and Christopher Ray are members of the executive committee of NGP Energy Capital Management, L.L.C. Although none of Messrs. Carter, Weber, Glick or Ray individually have voting or dispositive power over these shares, such individuals may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Each of Messrs. Carter, Weber, Glick and Ray disclaim beneficial ownership of these shares except to the extent of their respective pecuniary interest therein.

(5)

Includes 7,542,654 shares of Class A Common Stock and warrants exercisable for 17,233 shares of Class A Common Stock held by SMALLCAP World Fund, Inc. ("SCWF"), 8,209,667 shares of Class A Common Stock and warrants exercisable for 29,433 shares of Class A Common Stock held by The Growth Fund of America ("GFA") and 456,142 shares of Class A Common Stock held by Capital Group Global Equity Fund (Canada) ("CGGEF," and, together with SCWF and GFA, the "CRMC Stockholders"). Capital Research and Management Company ("CRMC") is the investment adviser to each of the CRMC Stockholders. CRMC and/or Capital World Investors ("CWI") may be deemed to be the beneficial owner of all of the securities held by the CRMC Stockholders; however, each of CRMC and CWI expressly disclaim that it is the beneficial owner of such securities. Julian N. Abdey, Mark E. Denning, Peter Eliot, Brady L. Enright, J. Blair Frank, Bradford F. Freer, Leo Hee, Claudia P. Huntington, Jonathan Knowles, Lawrence Kymisis, Harold H. La, Aidan O'Connell, Andraz Razen and Gregory W. Wendt, as portfolio managers, have voting and investment power over the securities held by SCWF. Christopher D. Buchbinder, Barry S. Crosthwaite, J. Blair Frank, Joanna F. Jonsson, Carl M. Kawaja, Michael T. Kerr, Ronald B. Morrow, Donald D. O'Neal, Martin Romo, Lawrence R. Solomon, James Terrile and Alan J. Wilson, as portfolio managers, have voting and investment power over the securities held by GFA. Carl M. Kawaja and Dina N. Perry, as portfolio managers, have voting and investment power over the securities held by CGGEF. The address for each of the CRMC Stockholders is c/o Capital Research and Management Company, 333 South Hope Street, 55th Floor, Los Angeles, CA 90071. The CRMC Stockholders may be affiliates of a broker-dealer. Each of the CRMC Stockholders acquired the shares being registered hereby in the ordinary course of its business.

(6)

These accounts are managed by direct or indirect subsidiaries of FMR LLC. Abigail P. Johnson is a Director, the Vice Chairman, the Chief Executive Officer and the President of FMR LLC. Members of the Johnson family, including Abigail P. Johnson, are the predominant owners, directly or through trusts, of Series B voting common shares of FMR LLC, representing 49% of the voting power of FMR LLC. The Johnson family group and all other Series B shareholders have entered into a shareholders' voting agreement under which all Series B voting common shares will be voted in accordance with the majority vote of Series B voting common shares. Accordingly, through their ownership of voting common shares and the execution of the shareholders' voting agreement, members of the Johnson family may be deemed, under the Investment Company Act of 1940, to form a controlling group with respect to FMR LLC. The address is 245 Summer Street, Boston, MA 02210.

(7)

Neither FMR LLC nor Abigail P. Johnson has the sole power to vote or direct the voting of the shares owned directly by the various investment companies registered under the Investment Company Act ("Fidelity Funds") advised by Fidelity Management & Research Company ("FMR Co"), a wholly owned subsidiary of FMR LLC, which power resides with the Fidelity Funds' Boards of Trustees. FMR Co carries out the voting of the shares under written guidelines established by the Fidelity Funds' Boards of Trustees.

(8)

Includes 11,218 restricted shares of our Class A Common Stock granted to each of Ms. Baldwin and Messrs. Tepper and Bandtel under our 2016 Long Term Incentive Plan.

79

HOUSEHOLDING INFORMATION

        Unless the Company has received contrary instructions, the Company may send a single copy of this proxy statement to any household at which two or more stockholders reside if we believe the stockholders are members of the same family. This process, known as "householding," reduces the volume of duplicate information received at any one household and helps to reduce our expenses. However, if stockholders prefer to receive multiple sets of the Company's disclosure documents at the same address this year or in future years, the stockholders should follow the instructions described below. Similarly, if an address is shared with another stockholder and together both of the stockholders would like to receive only a single set of the Company's disclosure documents, the stockholders should follow these instructions:

•

If the shares are registered in the name of the stockholder, the stockholder should contact the Company at its offices at Centennial Resource Development, Inc., 1401 Seventeenth Street, Suite 1000, Denver, Colorado 80202 to inform the Company of his or her request; or

•

If a bank, broker or other nominee holds the share, the stockholder should contact the bank, broker or other nominee directly.

SUBMISSION OF STOCKHOLDER PROPOSALS

        The Company's board of directors is aware of no other matter that may be brought before the special meeting. Under Delaware law, only business that is specified in the notice of special meeting to stockholders may be transacted at the special meeting.

STOCKHOLDER PROPOSALS FOR 2017 ANNUAL MEETING

        Any stockholder proposals submitted for inclusion in our proxy statement and form of proxy for our 2017 annual meeting of stockholders must be received by us a reasonable time before we begin to print and mail our proxy solicitation materials for such meeting in order to be considered for inclusion in our proxy statement and form of proxy. Any such proposals must comply with the requirements as to form and substance established by the SEC and should be mailed to Centennial Resource Development, Inc., 1401 Seventeenth Street, Suite 1000, Denver, Colorado 80202, Attn.: Secretary.

        Company stockholders may also make proposals and director nominations that are not intended to be included in our proxy statement and form of proxy, so long as the proposals or nominations comply with our bylaws. Our bylaws state that a stockholder must provide timely written notice of a proposal to be brought before the meeting and supporting documentation as well as be present at such meeting, either in person or by a representative. For our 2017 annual meeting, a stockholder's notice shall be timely received by us at our principal executive office not later than the close of business on the later of (i) the ninetieth (90th) day before the annual meeting and (ii) the tenth (10th) day following the day on which such public announcement of the date of the annual meeting is first made by us. Proxies solicited by our board of directors will confer discretionary voting authority with respect to these proposals, subject to the SEC's rules and regulations governing the exercise of this authority. Any such proposal should be mailed to Centennial Resource Development, Inc., 1401 Seventeenth Street, Suite 1000, Denver, Colorado 80202, Attn.: Secretary.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

        The Company files reports, proxy statements and other information with the SEC as required by the Securities Exchange Act of 1934, as amended. You can read the Company's SEC filings, including this proxy statement, over the Internet at the SEC's website at http://www.sec.gov. You may also read and copy any document the Company files with the SEC at the SEC public reference room located at 100 F Street, N.E., Room 1580 Washington, D.C., 20549. You may obtain information on the operation

80

of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain copies of the materials described above at prescribed rates by writing to the SEC, Public Reference Section, 100 F Street, N.E., Washington, D.C. 20549.

        If you would like additional copies of this proxy statement or if you have questions about the Proposals to be presented at the special meeting, you should contact the Company's proxy solicitation agent at the following address and telephone number:

Morrow Sodali LLC
470 West Avenue
Stamford, Connecticut 06902
Stockholders please call: (877) 787-9239
Banks and Brokers please call: (203) 658-9400
Email: CDEV.info@morrowsodali.com

If you are a Company stockholder and would like to request documents, please do so by                    , 2017, in order to receive them before the special meeting. If you request any documents from the Company, the Company will mail them to you by first class mail, or another equally prompt means.

        This document is a proxy statement of the Company for the special meeting. The Company has not authorized anyone to give any information or make any representation about the Company or the Proposals that is different from, or in addition to, that contained in this proxy statement. Therefore, if anyone does give you information of this sort, you should not rely on it. The information contained in this document speaks only as of the date of this document unless the information specifically indicates that another date applies.

81

INDEX TO FINANCIAL STATEMENTS

	Page
CENTENNIAL RESOURCE PRODUCTION, LLC (PREDECESSOR)—UNAUDITED FINANCIAL STATEMENTS
Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015		F-2
Condensed Consolidated Statements of Operations For the Three and Nine Months Ended September 30, 2016 and 2015		F-3
Condensed Consolidated Statement of Changes in Owners' Equity For the Nine Months Ended September 30, 2016		F-4
Condensed Consolidated Statements of Cash Flows For the Nine Months Ended September 30, 2016 and 2015		F-5
Notes to Condensed Consolidated Financial Statements		F-6
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP (PREDECESSOR)—AUDITED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm		F-17
Consolidated and Combined Balance Sheets as of December 31, 2015 and 2014		F-18
Consolidated and Combined Statements of Operations For the Years Ended December 31, 2015, 2014 and 2013		F-19
Consolidated and Combined Statements of Changes in Owners' Equity For the Years ended December 31, 2015, 2014 and 2013		F-20
Consolidated and Combined Statements of Cash Flows For the Years ended December 31, 2015, 2014 and 2013		F-21
Notes to Consolidated and Combined Financial Statements		F-22
SILVER RUN ACQUISITION CORPORATION—UNAUDITED PRO FORMA FINANCIAL STATEMENTS
Unaudited pro forma condensed consolidated combined financial information of Silver Run Acquisition Corporation for the three years ended December 31, 2015 and the nine months ended September 30, 2016.		F-48

F-1

CENTENNIAL RESOURCE PRODUCTION, LLC
(Predecessor)

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In Thousands)

	September 30, 2016			December 31, 2015
ASSETS
Current assets
Cash and cash equivalents	$	410		$	1,768
Accounts receivable, net		10,358			13,012
Derivative instruments, net		1,618			19,043
Prepaid and other current assets		864			322
Total current assets		13,250			34,145
Oil and natural gas properties, other property and equipment
Oil and natural gas properties, successful efforts method		718,999			651,596
Accumulated depreciation, depletion and amortization		(241,017	)		(180,946	)
Unproved oil and natural gas properties		139,690			105,897
Other property and equipment, net of accumulated depreciation of $1,665 and $868, respectively		1,703			2,240
Total property and equipment, net		619,375			578,787
Noncurrent assets
Derivative instruments, net		245			2,070
Other noncurrent assets		1,042			1,293
Total assets	$	633,912		$	616,295
LIABILITIES AND OWNERS' EQUITY
Current liabilities
Accounts payable and accrued expenses	$	23,579		$	19,985
Derivative instruments, net		1,000			—
Other current liabilities		243			2,148
Total current liabilities		24,822			22,133
Noncurrent liabilities
Revolving credit facility		124,000			74,000
Term loan, net of unamortized deferred financing costs		64,762			64,649
Asset retirement obligations		2,680			2,288
Deferred tax liability		1,954			2,361
Derivative instruments, net		557			—
Total liabilities		218,775			165,431
Owners' equity		415,137			450,864
Total liabilities and owners' equity	$	633,912		$	616,295

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

F-2

CENTENNIAL RESOURCE PRODUCTION, LLC
(Predecessor)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In Thousands)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2016			2015			2016			2015
Revenues
Oil sales	$	23,388		$	18,913		$	56,975		$	59,068
Natural gas sales		2,629			2,054			5,717			6,082
NGL sales		1,304			926			3,097			3,590
Total revenues		27,321			21,893			65,789			68,740
Operating expenses
Lease operating expenses		3,656			4,355			10,295			17,317
Severance and ad valorem taxes		1,432			1,555			3,523			3,833
Transportation, processing, gathering and other operating expenses		1,787			1,424			4,375			4,352
Depreciation, depletion, amortization and accretion of asset retirement obligations		18,454			19,880			60,939			64,003
Abandonment expense and impairment of unproved properties		1,649			—			2,546			3,851
Contract termination and rig stacking		—			221			—			2,388
General and administrative expenses		5,250			3,007			10,655			8,538
Total operating expenses		32,228			30,442			92,333			104,282
Gain on sale of oil and natural gas properties		(15	)		(9	)		(11	)		(2,688	)
Total operating loss		(4,892	)		(8,540	)		(26,533	)		(32,854	)
Other (expense) income
Interest expense		(1,983	)		(1,469	)		(5,422	)		(4,743	)
Gain (loss) on derivative instruments		1,741			13,344			(4,184	)		12,320
Other (expense) income		—			(9	)		6			(5	)
Total other (expense) income		(242	)		11,866			(9,600	)		7,572
Loss before income taxes		(5,134	)		3,326			(36,133	)		(25,282	)
Income tax benefit		—			—			406			—
Net (loss) income	$	(5,134	)	$	3,326		$	(35,727	)	$	(25,282	)

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

F-3

CENTENNIAL RESOURCE PRODUCTION, LLC
(Predecessor)

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN OWNER'S EQUITY

(Unaudited)

(In Thousands)

	Total Owners' Equity
Balance at December 31, 2015	$	450,864
Contributions		—
Net loss		(35,727	)
Balance at September 30, 2016	$	415,137

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

F-4

CENTENNIAL RESOURCE PRODUCTION, LLC
(Predecessor)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In Thousands)

	For the Nine Months Ended September 30,
	2016			2015
Cash flows from operating activities
Net loss	$	(35,727	)	$	(25,282	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Accretion of asset retirement obligations		129			101
Depreciation, depletion and amortization		60,810			63,902
Abandonment expense and impairment of unproved properties		2,546			3,851
Deferred tax expense		(406	)		—
Gain on sale of oil and natural gas properties		(11	)		(2,688	)
Loss (gain) on derivative instruments		4,184			(12,320	)
Net cash received for derivative settlements		16,623			25,972
Amortization of debt issuance costs		363			360
Changes in operating assets and liabilities:
Decrease in accounts receivable		3,021			4,956
Increase in prepaid and other assets		(165	)		(656	)
Increase (decrease) in accounts payable and other liabilities		144			(9,722	)
Net cash provided by operating activities		51,511			48,474
Cash flows from investing activities
Acquisition of oil and natural gas properties		(55,566	)		(38,315	)
Development of oil and natural gas properties		(45,203	)		(133,595	)
Purchases of other property and equipment		(206	)		(2,097	)
Development of assets held for sale		—			—
Proceeds from sales of oil and natural gas properties and other assets		—			2,691
Net cash used by investing activities		(100,975	)		(171,316	)
Cash flows from financing activities
Proceeds from revolving credit facility		55,000			84,000
Repayment of revolving credit facility		(5,000	)		(83,000	)
Capital contributions		—			110,656
Financing obligation		(1,894	)		(1,238	)
Debt issuance costs		—			(199	)
Net cash provided by financing activities		48,106			110,219
Net decrease in cash and cash equivalents		(1,358	)		(12,623	)
Cash and cash equivalents, beginning of period		1,768			13,017
Cash and cash equivalents, end of period	$	410		$	394
Supplemental cash flow information
Cash paid for interest	$	4,993		$	4,340
Supplemental noncash activity
Accrued capital expenditures included in accounts payable and accrued expenses	$	16,339		$	14,946

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

F-5

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Organization and Nature of Operations

        Centennial Resource Production, LLC, a Delaware limited liability company formerly named Atlantic Energy Holdings, LLC ("Centennial OpCo" or the "Predecessor"), was formed on August 30, 2012 by its management members, third-party investors and NGP Natural Resources X, LP ("NGP X"), an affiliate of Natural Gas Partners, a family of energy-focused private equity investment funds ("NGP"). Centennial OpCo is engaged in the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves, primarily in the Delaware Basin of West Texas.

        For additional information regarding the organization and formation of the Predecessor please refer to Note 1—Organization and Nature of Operations in the Predecessor's audited consolidated and combined financial statements for the year ended December 31, 2015, included in the Proxy Statement of Silver Run Acquisition Corporation filed with the Securities and Exchange Commission on September 23, 2016 (the "Audited Financial Statements").

Note 2—Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards

Basis of Presentation

        The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP"). The condensed consolidated financial statements do not include all information and notes required by U.S. GAAP for complete financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to the Audited Financial Statements. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying condensed consolidated financial statements.

Assumptions, Judgments and Estimates

        The preparation of the Predecessor's condensed consolidated financial statements requires the Predecessor's management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

        The more significant areas requiring the use of assumptions, judgments and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) determining fair value and allocating purchase price in connection with business combinations; (6) valuation of derivative instruments; and (7) accrued revenue and related receivables.

F-6

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)

Significant Accounting Policies

        The significant accounting policies followed by the Predecessor are set forth in Note 2—Basis of Presentation, Summary of Significant Accounting Policies, and Recently Issued Accounting Standards in the Audited Financial Statements.

Recently Issued Accounting Standards

        In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The new standard becomes effective for the Predecessor on January 1, 2018, with early adoption is permitted. The Predecessor is evaluating the impact, if any, that the adoption of this update will have on the Predecessor's condensed consolidated financial statements and related disclosures.

        In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Predecessor is evaluating the impact, if any, that the adoption of this update will have on the Predecessor's condensed consolidated financial statements and related disclosures.

        In February 2016, the FASB issued ASU No. 2016-02, Leases, which requires all leasing arrangements to be presented in the balance sheet as liabilities along with a corresponding asset. This ASU will replace most existing leases guidance in U.S. GAAP when it becomes effective. The new standard becomes effective for the Predecessor on January 1, 2019. Although early adoption is permitted, the Predecessor does not plan to early adopt the ASU. The standard requires the use of the modified retrospective transition method. The Predecessor is evaluating the impact, if any, that the adoption of this update will have on the Predecessor's condensed consolidated financial statements and related disclosures.

        In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This guidance is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance. In August 2015, the FASB deferred the effective date of the new revenue recognition standard by one year. The revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Predecessor is evaluating the impact, if any, that the adoption of this update will have on our consolidated and combined financial statements and related disclosures.

F-7

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)

        Other than as disclosed above or set forth in Note 2—Basis of Presentation, Summary of Significant Accounting Policies, and Recently Issued Accounting Standards in the Predecessor's Audited Financial Statements, there are no other new accounting standards that would have a material impact on the Predecessor's condensed consolidated financial statements and disclosures.

Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses

        Accounts receivable are comprised of the following:

	September 30, 2016			December 31, 2015
	(in thousands)
Oil and natural gas	$	8,372		$	5,789
Joint interest billings		892			1,514
Hedge settlements		751			3,956
Other		434			1,844
Allowance for doubtful accounts		(91	)		(91	)
Accounts receivable, net	$	10,358		$	13,012

        Accounts payable and accrued expenses are comprised of the following:

	September 30, 2016		December 31, 2015
	(in thousands)
Accounts payable	$	7,365	$	1,827
Accrued capital expenditures		11,110		11,700
Revenues payable		2,698		3,439
Other		2,406		3,019
Accounts payable and accrued expenses	$	23,579	$	19,985

Note 4—Acquisitions

        In June 2016, the Predecessor completed the acquisition of unproved and proved properties in the Delaware Basin. Total cash consideration paid by the Predecessor was $33.0 million, including usual and customary post-closing adjustments. The Predecessor determined that the acquisition met the criteria for a business combination under FASB Accounting Standard Codification ("ASC") Topic 805, Business Combinations. The Predecessor allocated the final purchase price to the acquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below.

F-8

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 4—Acquisitions (Continued)

Refer to Note 7—Fair Value Measurements for additional discussion on the valuation techniques used in determining the fair value of the acquired properties.

	September 30, 2016
	(in thousands)
Cash consideration	$	32,979
Fair value of assets and liabilities acquired:
Proved oil and natural gas properties		15,374
Unproved oil and natural gas properties		18,071
Total fair value of oil and natural gas properties acquired		33,445
Revenue Suspense		(400	)
Asset retirement obligation		(66	)
Total fair value of net assets acquired	$	32,979

Note 5—Asset Retirement Obligations

        The following table summarizes the changes in the Predecessor's asset retirement obligations for the nine months ended September 30, 2016:

	Nine Months Ended September 30, 2016
	(in thousands)
Asset retirement obligations, beginning of period	$	2,288
Liabilities assumed		66
Liabilities incurred		174
Liabilities settled		(9	)
Accretion expense		129
Revision of estimated liabilities		32
Asset retirement obligations, end of period	$	2,680

Note 6—Derivative Instruments

        The Predecessor periodically uses derivative instruments to mitigate its exposure to a decline in commodity prices and the corresponding negative impact on cash flow available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. Depending on changes in oil and natural gas futures markets and the Predecessor's view of underlying supply and demand trends, it may increase or decrease its hedging positions.

F-9

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 6—Derivative Instruments (Continued)

        The following table summarizes the approximate volumes and average contract prices of swap and collar contracts the Predecessor had in place as of September 30, 2016:

	2016			2017
Crude Oil Swaps:
Notional volume (Bbl)		193,200			675,250
Weighted average floor price ($/Bbl)	$	55.21		$	50.41
Crude Oil Basis Swaps:
Notional volume (Bbl)		320,300			127,750
Weighted average floor price ($/Bbl)	$	(0.45	)	$	(0.20	)
Natural Gas Swaps:
Notional volume (MMBtu)		—			1,460,000
Weighted average floor price ($/MMBtu)	$	—		$	2.94

        In a typical commodity swap agreement, if the agreed upon published third-party index price ("index price") is lower than the swap fixed price, the Predecessor receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Predecessor pays the difference. In addition, the Predecessor has entered into basis swap contracts in order to hedge the difference between the NYMEX index price and a local index price. When the actual differential exceeds the fixed price provided by the basis swap contract, the Predecessor receives the difference from the counterparty; when the differential is less than the fixed price provided by the basis swap contract, the Predecessor pays the difference to the counterparty.

        The Predecessor's commodity derivatives are measured at fair value and are included in the accompanying condensed consolidated balance sheets as derivative assets and liabilities. The fair value of the commodity contracts was a net asset of $0.3 million and $21.1 million as of September 30, 2016 and December 31, 2015, respectively.

F-10

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 6—Derivative Instruments (Continued)

        The following tables below summarize the gross fair value of derivative assets and liabilities and the effect of netting on the condensed consolidated balance sheets:

	September 30, 2016
	Balance Sheet Classification	Gross Amounts		Netting Adjustments			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	(in thousands)
Assets
Derivative instruments	Current assets	$	2,642	$	(1,024	)	$	1,618
Derivative instruments	Noncurrent assets		277		(32	)		245
Total assets		$	2,919	$	(1,056	)	$	1,863
Liabilities
Derivative instruments	Current liabilities	$	1,011	$	(11	)	$	1,000
Derivative instruments	Noncurrent Liabilities		659		(102	)		557
Total liabilities		$	1,670	$	(113	)	$	1,557

	December 31, 2015
	Balance Sheet Classification	Gross Amounts		Netting Adjustments			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	(in thousands)
Assets
Derivative instruments	Current assets	$	19,469	$	(426	)	$	19,043
Derivative instruments	Noncurrent assets		2,071		(1	)		2,070
Total assets		$	21,540	$	(427	)	$	21,113

        The Predecessor's oil and natural gas derivative instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in the Predecessor's condensed consolidated statements of operations. The derivative instruments are recorded at fair value on the condensed consolidated balance sheets and any gains and losses are recognized in current period earnings.

        The following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for the periods presented:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2016			2015			2016		2015
	(in thousands)
Loss (gain) on derivative instruments	$	(1,741	)	$	(13,344	)	$	4,184	$	(12,320	)

F-11

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 6—Derivative Instruments (Continued)

        The Predecessor is exposed to financial risks associated with its derivative contracts from non-performance by its counterparties. The Predecessor mitigates its exposure to any single counterparty by contracting with a number of financial institutions, each of which have a high credit rating and is a member of its bank credit facility. The Predecessor's member banks do not require it to post collateral for its hedge liability positions. Because some of the member banks have discontinued hedging activities, in the future the Predecessor may hedge with counterparties outside its bank group to obtain competitive terms and to spread counterparty risk.

        The Predecessor did not incur any losses due to counterparty non-performance during the three and nine months ended September 30, 2016 or the year ended December 31, 2015.

Note 7—Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

        The Predecessor has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

        The following table is a listing of the Predecessor's assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of September 30, 2016 and December 31, 2015 (in thousands):

	Level 1		Level 2		Level 3
	(in thousands)
Commodity derivative asset, net(1)
September 30, 2016	$	—	$	306	$	—
December 31, 2015	$	—	$	21,113	$	—

(1)

This represents a financial asset that is measured at fair value on a recurring basis.

        Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Predecessor as well as the general classification of such instruments pursuant to the above fair value hierarchy. There were no transfers between Level 1, Level 2 or Level 3 during any period presented.

Derivatives

        The Predecessor uses Level 2 inputs to measure the fair value of oil and natural gas commodity derivatives. The Predecessor uses industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be

F-12

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 7—Fair Value Measurements (Continued)

supported by observable data. The Predecessor utilizes its counterparties' valuations to assess the reasonableness of its own valuations.

Nonrecurring Fair Value Measurements

        The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Predecessor's management at the time of the valuation. Refer to Note 4—Acquisitions and Divestitures for additional information on the fair value of assets acquired during 2016.

Other Financial Instruments

        The carrying amounts of the Predecessor's cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying values of the amounts outstanding under the Predecessor's credit agreement approximate fair value because the variable interest rates are reflective of current market conditions.

Note 8—Long-Term Debt

Credit Agreement

        The Predecessor's amended and restated credit agreement ("credit agreement"), dated October 15, 2014, includes both a term loan commitment of $65.0 million (the "term loan") and a revolving credit facility (the "revolving credit facility") with commitments of $500.0 million (subject to the borrowing base), with a sublimit for letters of credit of $15.0 million. The revolving credit facility matures on October 15, 2019 and the term loan matures on April 15, 2018.

        The borrowing base under the revolving credit facility is determined at the discretion of the lenders and depends on, among other things, the volumes of the Predecessor's proved oil and natural gas reserves and estimated cash flows from these reserves and the Predecessor's commodity hedge positions. In April 2016, the borrowing base was reaffirmed at $140.0 million. The next regular redetermination date is scheduled for October 2016.

        As of September 30, 2016, borrowings under the revolving credit facility were $124.0 million and $0.5 million of outstanding letters of credit, leaving $15.5 million in borrowing capacity under the revolving credit facility.

F-13

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 8—Long-Term Debt (Continued)

        The term loan, net of unamortized deferred financing costs on the accompanying condensed consolidated balance sheets as of September 30, 2016 and December 31, 2015, consisted of the following:

	September 30, 2016			December 31, 2015
	(in thousands)
Term loan	$	65,000		$	65,000
Unamortized deferred financing costs		(238	)		(351	)
Term loan, net of unamortized deferred financing costs	$	64,762		$	64,649

        The credit agreement also has customary covenants with which the Predecessor was in compliance as of September 30, 2016.

Note 9—Incentive Unit Compensation

        There have been no material changes in issued, forfeited or vested incentive units during the nine months ended September 30, 2016. Please refer to Note 9—Incentive Unit Compensation in the Audited Financial Statements.

        Incentive units are accounted for as liability awards under FASB ASC Topic 718, Compensation—Stock Compensation, with compensation expense based on period-end fair value. The achievement of payout conditions is a performance condition that requires the Predecessor to assess, at each reporting period, the probability that an event of payout will occur. Compensation cost is required to be recognized at such time that the payout terms are probable of being met. At the grant dates and subsequent reporting periods, the Predecessor did not deem as probable that such payouts would be achieved.

Note 10—Transactions with Related Parties

        In May 2016, the Predecessor acquired acreage in close proximity to its operating area in Reeves County, Texas and wellbore only rights in an uncompleted horizontal wellbore for approximately $9.8 million from Caird DB, LLC, an affiliate of NGP.

        The Predecessor is party to a 15-year gas gathering agreement with PennTex Permian, LLC ("PennTex"), an NGP affiliated company, which terminates on April 1, 2029 and is subject to one-year extensions at either party's election. Under the agreement, PennTex gathers and processes the Predecessor's gas. PennTex purchases the extracted natural gas liquids from the Predecessor, net of gathering fees and an agreed percentage of the actual proceeds from the sale of the residue natural gas and natural gas liquids. Net payments received from PennTex for the three months ended September 30, 2016 and 2015 were $0.5 million and $0.2 million, respectively. Net payments received from PennTex for the nine months ended September 30, 2016 and 2015 were $0.9 million and $0.9 million, respectively. As of September 30, 2016, the Predecessor recorded a receivable of $0.3 million from PennTex.

F-14

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 10—Transactions with Related Parties (Continued)

        In October 2014, the gas gathering agreement with PennTex was amended to construct an expansion of the gathering system and a receipt point. Please refer to Note 11—Commitments and Contingencies.

        From time to time, the Predecessor obtains services related to its drilling and completion activities from affiliates of NGP. In particular, the Predecessor has paid the following amounts to the following affiliates of NGP for such services: (i) approximately $0.3 million during the nine months ended September 30, 2016 to Cretic Energy Services, LLC; and (ii) approximately $3.3 million during the nine months ended September 30, 2016 to RockPile Energy Services, LLC. On September 8, 2016, Rockpile Energy Services, LLC, was purchased from NGP by a third party and is no longer a related party with the Predecessor.

Note 11—Commitments and Contingencies

Commitments

        In October 2014, the Predecessor's gas gathering agreement with PennTex was amended to provide for the construction of an expansion of the gathering system and a receipt point. The Predecessor will reimburse PennTex for the total cost of the expansion project. The Predecessor will pay a minimum fee of $7,000 per day until PennTex recoups the capital outlay for the expansion project. At September 30, 2016 a short-term liability of $0.3 million was in included in Other current liabilities on the condensed consolidated balance sheets. For the three and nine months ended September 30, 2016, the Predecessor made payments, including interest, of $0.2 million and $1.0 million, respectively.

        In December 2015, the Predecessor entered into a transportation and gathering services agreement by which a transporter agreed to construct a crude oil gathering and transportation system capable of transporting crude oil from certain Company wells in Reeves and Ward Counties, Texas to destination points in Crane and Midland, Texas (the "Transportation System"), and the Predecessor agreed to dedicate and ship on the Transportation System all crude oil owned or controlled by the Predecessor from oil and gas leases covering approximately 28,000 gross acres located within a designated area of mutual interest in Reeves and Ward Counties. The agreement has a primary term of 12 years from October 1, 2016, the date the Transportation System was first put into service, and may be extended at the Company's option for two successive two-year terms and, thereafter, is automatically extended for successive one-year terms unless terminated by the Predecessor or the transporter upon 60 days' prior notice.

        In July 2016, the Predecessor entered into a crude oil purchase agreement by which the Predecessor agreed to sell all of its crude oil production that is produced at receipt points identified in the agreement commencing on the October 1, 2016 in-service date of the Transportation System. The purchaser is obligated to purchase the crude oil at the receipt points identified in the agreement and transport it on the Transportation System. The agreement has an initial term of nine months from October 1, 2016, the date the Transportation System entered commercial service, and evergreen 30-day renewal terms unless terminated by the Predecessor or the purchaser on 30 days' prior notice. The price received by the Predecessor for the crude oil it sells under the agreement is based generally on NYMEX pricing subject to marketing and other adjustments, and varies depending on whether the oil

F-15

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 11—Commitments and Contingencies (Continued)

is transported to Crane or Midland, Texas and on whether the oil is transported before or after the Transportation System is connected to a pipeline in Crane, Texas or a terminal in Midland, Texas.

        There have been no other material changes in commitments during the nine months ended September 30, 2016. Please refer to Note 11—Commitment and Contingencies in the Audited Financial Statements.

Contract Termination and Rig Stacking

        In light of the low commodity price environment, the Predecessor curtailed its drilling activity during 2015. For the three and nine months ended September 30, 2015, the Predecessor incurred drilling rig termination fees of $0.2 million and $2.4 million, respectively, which are recorded in the Contract termination and rig stacking line item in the accompanying condensed consolidated statements of operations.

Contingencies

        In the ordinary course of business, the Predecessor may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Predecessor's financial position, results of operations or cash flows. Management is unaware of any pending litigation brought against the Predecessor requiring the reserve of a contingent liability as of the date of these condensed consolidated financial statements.

Note 12—Subsequent Events

        On October 11, 2016, Centennial Resource Development, Inc. (formerly known as Silver Run Acquisition Corporation) (CDEV) consummated the previously announced acquisition of approximately 89% of the outstanding membership interests in the Predecessor (the "Business Combination"), pursuant to (i) the 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"), the Predecessor and New Centennial, LLC, a Delaware limited liability company ("NewCo"), (ii) that certain Assignment Agreement, dated as of October 7, 2016, between NewCo and Silver Run Acquisition Corporation and (iii) that certain Joinder Agreement, dated as of October 7, 2016, by Silver Run Acquisition Corporation.

        In connection with the Business Combination CDEV paid the Centennial Contributors $1,186,744,348 in aggregate cash consideration and the Centennial Contributors retained 20,000,000 common membership interests in the Predecessor, representing approximately 11% of the outstanding membership interests in the Predecessor.

        On October 11, 2016, the Predecessor also entered into an amendment to the credit agreement to, among other things (i) permit the transaction, (ii) reflect the repayment in full of all term loans thereunder, (iii) increase the borrowing base from $140.0 million to $200.0 million, (iv) increase the interest rate to LIBOR plus 2.25% - 3.25%, and (v) require the Predecessor to have sufficient liquidity and satisfy a maximum leverage ratio in order to make dividends. As of the closing date of the Business Combination, the Predecessor has no outstanding debt and approximately $100.0 million of cash on hand.

F-16

Report of Independent Registered Public Accounting Firm

The Board of Directors
Centennial Resource Development, Inc.:

        We have audited the accompanying consolidated and combined balance sheets of Centennial Resource Production, LLC and Celero Energy Company, LP (Predecessor, the Company) as of December 31, 2015 and 2014, and the related consolidated and combined statements of operations, changes in owners' equity, and cash flows for each of the years in the three-year period ended December 31, 2015. These consolidated and combined financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated and combined financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of Centennial Resource Production, LLC and Celero Energy Company, LP (Predecessor) as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

        As discussed in Note 2 to the consolidated and combined financial statements, the balance sheets, and the related statements of operations, changes in equity, and cash flows have been prepared on a consolidated and combined basis of accounting as a result of the reorganization of interests under common control.

/s/ KPMG LLP

Denver, Colorado
April 5, 2016, except as to Note 14, which is as of May 17, 2016

F-17

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

CONSOLIDATED AND COMBINED BALANCE SHEETS

	December 31,
	2015			2014
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	1,768		$	13,017
Accounts receivable, net		13,012			23,117
Derivative instruments, net		19,043			30,422
Prepaid and other current assets		322			790
Total current assets		34,145			67,346
Oil and natural gas properties, other property and equipment
Oil and natural gas properties, successful efforts method		651,596			541,119
Accumulated depreciation, depletion and amortization		(180,946	)		(91,735	)
Unproved oil and natural gas properties		105,897			90,645
Other property and equipment, net of accumulated depreciation of $868 and $139, respectively		2,240			595
Total property and equipment, net		578,787			540,624
Noncurrent assets
Derivative instruments, net		2,070			6,365
Other noncurrent assets		1,293			1,434
Total assets	$	616,295		$	615,769
LIABILITIES AND OWNERS' EQUITY
Current liabilities
Accounts payable and accrued expenses	$	19,985		$	101,295
Other current liabilities		2,148			2,217
Total current liabilities		22,133			103,512
Noncurrent liabilities
Revolving credit facility		74,000			65,000
Term loan, net of unamortized deferred financing costs		64,649			64,568
Asset retirement obligations		2,288			1,824
Deferred tax liability		2,361			2,933
Total liabilities		165,431			237,837
Owners' equity		450,864			377,932
Total liabilities and owners' equity	$	616,295		$	615,769

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

F-18

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

	For the Year Ended December 31,
	2015			2014			2013
	(in thousands)
Revenues
Oil sales	$	77,643		$	114,955		$	65,863
Natural gas sales		7,965			9,670			3,024
NGL sales		4,852			7,200			3,087
Total revenues		90,460			131,825			71,974
Operating expenses
Lease operating expenses		21,173			17,690			19,106
Severance and ad valorem taxes		5,021			6,875			4,153
Transportation, processing, gathering and other operating expenses		5,732			4,772			1,291
Depreciation, depletion, amortization and accretion of asset retirement obligations		90,084			69,110			29,285
Abandonment expense and impairment of unproved properties		7,619			20,025			8,561
Exploration		84			—			—
Contract termination and rig stacking		2,387			—			—
General and administrative expenses		14,206			31,694			16,842
Total operating expenses		146,306			150,166			79,238
(Gain) loss on sale of oil and natural gas properties		(2,439	)		2,096			(16,756	)
Total operating (loss) income		(53,407	)		(20,437	)		9,492
Other (expense) income
Interest expense		(6,266	)		(2,475	)		(513	)
Gain (loss) on derivative instruments		20,756			41,943			(4,410	)
Other income		20			281			122
Total other (expense) income		14,510			39,749			(4,801	)
(Loss) income before income taxes		(38,897	)		19,312			4,691
Income tax benefit (expense)		572			(1,524	)		(1,079	)
Net (loss) income		(38,325	)		17,788			3,612
Less net loss attributable to noncontrolling interest		—			(2	)		(6	)
Net (loss) income attributable to the predecessor	$	(38,325	)	$	17,790		$	3,618

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

F-19

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN OWNERS' EQUITY

	Total Owners' Equity			Noncontrolling Interest in Subsidiary			Total Equity
	(in thousands)
Balance at December 31, 2012	$	296,980		$	—		$	296,980
Contributions		118,000			694			118,694
Distributions		(25,340	)		—			(25,340	)
Owners' promissory note receivable		(3,399	)		—			(3,399	)
Net income (loss)		3,618			(6	)		3,612
Balance at December 31, 2013		389,859			688			390,547
Contributions		59,776			150			59,926
Repurchase of equity interests		(119,272	)		—			(119,272	)
Deemed contribution from sale of assets		21,489			(836	)		20,653
Deemed contribution from parent for payment of incentive units		12,420			—			12,420
Deemed distribution in connection with common control acquisition		(4,130	)		—			(4,130	)
Net income (loss)		17,790			(2	)		17,788
Balance at December 31, 2014		377,932			—			377,932
Contributions		111,396			—			111,396
Deemed distribution from sale of assets		(139	)		—			(139	)
Net loss		(38,325	)		—			(38,325	)
Balance at December 31, 2015	$	450,864		$	—		$	450,864

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

F-20

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

	For the Year Ended December 31,
	2015			2014			2013
	(in thousands)
Cash flows from operating activities
Net (loss) income	$	(38,325	)	$	17,788		$	3,612
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Accretion of asset retirement obligations		139			156			358
Depreciation, depletion and amortization		89,945			68,954			28,927
Noncash incentive compensation expense		—			12,420			—
Abandonment expense and impairment of unproved properties		7,619			20,025			8,524
Write-off of deferred S-1 related expense		1,585			—			—
Deferred tax (benefit) expense		(572	)		1,524			1,079
(Gain) loss on sale of oil and natural gas properties		(2,439	)		2,096			(16,756	)
(Gain) loss on derivative instruments		(20,756	)		(41,943	)		4,410
Net cash received for derivative settlements		35,493			4,611			(12,651	)
Payment of derivative contract premiums		—			—			(994	)
Recovery of bad debt		—			(777	)		1,128
Amortization of debt issuance costs		482			316			210
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable		5,244			(6,322	)		(1,016	)
Increase in prepaid and other assets		(864	)		(79	)		(2,054	)
(Decrease) increase in accounts payable and other liabilities		(8,669	)		18,479			(1,361	)
Net cash provided by operating activities		68,882			97,248			13,416
Cash flows from investing activities
Acquisition of oil and natural gas properties		(43,223	)		(22,167	)		(27,412	)
Development of oil and natural gas properties		(156,006	)		(275,683	)		(146,463	)
Purchases of other property and equipment		(2,097	)		(453	)		(543	)
Proceeds from sales of oil and natural gas properties and other assets		2,691			72,382			46,316
Development of assets held for sale		—			(14,240	)		(37,915	)
Proceeds from sale of Atlantic Midstream, net of cash sold		—			71,781			—
Change in cash held in escrow		—			5,000			29,500
Net cash used by investing activities		(198,635	)		(163,380	)		(136,517	)
Cash flows from financing activities
Proceeds from revolving credit facility		92,000			196,000			57,000
Repayment of revolving credit facility		(83,000	)		(160,000	)		(28,000	)
Financing obligation		(1,633	)		—			—
Capital contributions		111,396			59,776			114,859
Debt issuance costs		(259	)		(1,637	)		(471	)
Repurchase of equity		—			(119,272	)		(21,102	)
Capital distribution		—			—			(4,238	)
Proceeds from term loan		—			65,000			—
Distribution in connection with common control acquisition		—			(3,051	)		—
Contributions received from noncontrolling interest		—			150			694
Net cash provided by financing activities		118,504			36,966			118,742
Net decrease in cash and cash equivalents		(11,249	)		(29,166	)		(4,359	)
Cash and cash equivalents, beginning of period		13,017			42,183			46,542
Cash and cash equivalents, end of period	$	1,768		$	13,017		$	42,183
Supplemental cash flow information
Cash paid for interest	$	5,782		$	1,935		$	232
Supplemental noncash activity
Accrued capital expenditures included in accounts payable and accrued expenses	$	13,124		$	81,510		$	5,099
Owners' promissory note receivable		—			—			3,399
Financing obligation		3,770			—			—

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

F-21

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 1—Organization and Nature of Operations

        Centennial Resource Production, LLC, a Delaware limited liability company formerly named Atlantic Energy Holdings, LLC ("Centennial OpCo"), was formed on August 30, 2012 by its management members, third-party investors and NGP Natural Resources X, LP ("NGP X"), an affiliate of Natural Gas Partners ("NGP"), a family of energy-focused private equity investment funds. Centennial OpCo is engaged in the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves, primarily in the Delaware Basin of West Texas.

        Atlantic Midstream was formed on May 21, 2013, as a Delaware limited liability company and is constructing assets to gather and process natural gas in the Delaware Basin of West Texas. Centennial OpCo sold its interests in Atlantic Midstream on February 12, 2014 (refer to Note 4—Acquisitions and Divestitures).

        On March 31, 2014, all of Centennial OpCo's employee members sold their membership interests to Centennial OpCo. Contemporaneously, Centennial Resource Development, LLC, a Delaware limited liability company formed by NGP X and certain management members ("Centennial HoldCo"), agreed to purchase the entirety of Centennial OpCo's issued and outstanding incentive units. On April 30, 2014, NGP X contributed and conveyed its membership interests in Centennial OpCo to Centennial HoldCo. On May 9, 2014, Centennial OpCo's remaining members sold their membership interests to Centennial OpCo. As a result of these transactions, Centennial OpCo became a wholly-owned subsidiary of Centennial HoldCo. Centennial HoldCo is a holding company with no independent operations apart from its ownership interests in Centennial OpCo. NGP X controls Centennial HoldCo through ownership of 99.0% of its membership interests.

        Celero Energy Company, LP, a Delaware limited partnership ("Celero"), was formed on September 22, 2006, by its general partner, Celero Energy Management, LLC ("Celero GP"), its management team and Natural Gas Partners VIII, L.P. ("NGP VIII"), also an affiliate of NGP. Celero is engaged in 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 gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo (the "Combination"). As a result of the transaction, Centennial HoldCo owned approximately 72% of Centennial OpCo, and Celero owned the remaining 28%.

        In 2015, NGP Centennial Follow-On LLC ("Follow-On"), a Delaware limited liability company controlled by NGP but the economic interests in which are owned by unaffiliated third party investors and management, contributed $84.2 million to Centennial OpCo in exchange for membership interests in Centennial OpCo. In addition, Centennial HoldCo contributed approximately $27.2 million to Centennial OpCo in exchange for additional membership interests in Centennial OpCo. Accordingly, Centennial HoldCo, Celero and Follow-On own an approximate 61.2%, 21.2% and 17.6% membership interest in Centennial OpCo, respectively.

F-22

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards

Basis of Presentation

        Through the delegation of authority of the general partners of NGP X and NGP VIII to NGP Energy Capital Management, L.L.C. ("NGP ECM"), all power and authority of the respective fund limited partnership in effectuating its core investment, management and divestment function is controlled by NGP ECM. As all power and authority to control the core functions of Centennial OpCo and Celero (collectively, the "Predecessor") are controlled by NGP X and NGP VIII, respectively, the Combination has been accounted for as a reorganization of entities under common control in a manner similar to a pooling of interests. The results of Centennial OpCo and Celero have been combined for all periods in which common control existed for financial reporting purposes. All significant intercompany and intra-company balances and transactions have been eliminated.

        Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying consolidated and combined financial statements.

        Under certain contracts, when NGLs are extracted from the gas stream, processors receive a portion of the sales value from both the residue gas and the NGLs as a processing fee and remit the contractual proceeds to us. Prior to 2015, revenue was recognized net of these processing fees for residue gas and NGLs sold under these contracts as allowed under Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 605, Revenue Recognition. Increasing NGL production has resulted in processing costs becoming more significant. Accordingly, the Predecessor changed its policy to record these processing costs with operating costs as allowed under ASC 605. Beginning in 2015, the Predecessor's realized prices for sales under these contracts reflect the value of 100% of the residue gas and NGLs yielded by processing, rather than the value associated with the contractual proceeds it received. The related processing fees now are included in Transportation, processing, gathering, and other operating expenses. Financial statements for periods prior to 2015 have been reclassified to reflect this change in accounting treatment. There was no impact on operating income.

Assumptions, Judgments and Estimates

        In the course of preparing the Predecessor's consolidated and combined financial statements, the Predecessor's management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

        The more significant areas requiring the use of assumptions, judgments and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) determining fair value and allocating purchase price in connection with business combinations; (6) valuation of derivative instruments; and (7) accrued revenue and related receivables.

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

F-23

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)

Significant Accounting Policies

Cash and Cash Equivalents

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

Accounts Receivable

        Accounts receivable consists mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Predecessor operates. For receivables from joint interest owners, the Predecessor typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and natural gas receivables are collected within two months and the Predecessor has had minimal bad debts. The Predecessor establishes an allowance for doubtful accounts equal to the estimable portions of accounts receivable for which failure to collect is probable. The Predecessor's allowance for doubtful accounts totaled $0.1 million and $0.3 million as of December 31, 2015 and 2014, respectively.

Credit Risk and Other Concentrations

        The Predecessor sells oil and natural gas to various third party purchasers. The future availability of a ready market for oil and natural gas depends on numerous factors outside the Predecessor's control, none of which can be predicted with certainty. For the years ended December 31, 2015, 2014 and 2013, the Predecessor had one major customer, Plains Marketing, LP, which accounted for 64%, 78% and 72%, respectively, of total revenue for those years. The Predecessor does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

        By using derivative instruments to economically hedge exposures to changes in commodity prices, the Predecessor exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Predecessor, which creates credit risk. As of December 31, 2015, and through the filing date of this report, all of the Predecessor's derivative counterparties were members of the Predecessor's credit facility lender group. The credit facility is secured by the Predecessor's proved oil and natural gas properties and therefore, the Predecessor is not required to post any collateral. The Predecessor does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Predecessor would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $21.5 million at December 31, 2015. The Predecessor minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; and (ii) monitoring the creditworthiness of the Predecessor's counterparties on an ongoing basis. In accordance with the Predecessor's standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

F-24

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)

        The Predecessor places its temporary cash investments with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution. For the years ended December 31, 2015, 2014 and 2013, the Predecessor has not incurred losses related to these investments.

Oil and Natural Gas Properties

        The Predecessor follows the successful efforts method of accounting for its oil and natural gas properties. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells and development wells are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. As of December 31, 2015 and 2014, no costs were capitalized in connection with exploratory wells in progress. Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized in income.

        Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. The Predecessor evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on or otherwise attributed to the property. For the year ended December 31, 2015, the Predecessor recorded abandonment expense and impairment of unproved properties of $7.6 million for leases which had expired, or were expected to expire. For the year ended December 31, 2014, the Predecessor recorded abandonment expense and impairment of unproved properties of $20.0 million, of which $13.8 million was attributable to an impairment of unproved properties and $6.2 million was attributable to leases which had expired, or were expected to expire. For the year ended December 31, 2013, the Predecessor recorded an impairment of $7.4 million attributable to lease expirations.

        The Predecessor reviews its proved oil and natural gas properties for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Predecessor estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Predecessor will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows. There were no impairments of proved oil and natural gas properties during the years ended December 31, 2015, 2014 and 2013.

F-25

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)

Other Property and Equipment

        Other property and equipment such as office furniture and equipment, buildings, vehicles, and computer hardware and software is recorded at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets ranging from three to twenty years. Major renewals and improvements are capitalized while expenditures for maintenance and repairs are expensed as incurred. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Deferred Loan Costs

        Deferred loan costs related to the Predecessor's revolving credit facility are included in the line item Other noncurrent assets in the consolidated and combined balance sheets and are stated at cost, net of amortization, and are amortized to interest expense on a straight line basis over the borrowing term. Please refer to Recently Issued Accounting Standards, for additional discussion of deferred loan costs related to the Predecessor's term loan.

Derivative Financial Instruments

        In order to manage its exposure to oil and natural gas price volatility, the Predecessor enters into derivative transactions from time to time, including commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements relating to the price risk associated with a portion of its production. To the extent legal right of offset exists with a counterparty, the Predecessor reports derivative assets and liabilities on a net basis.

        The Predecessor records derivative instruments on the consolidated and combined balance sheets as either an asset or liability measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. The Predecessor's derivatives have not been designated as hedges for accounting purposes. For additional discussion on derivatives, please refer to Note 5—Derivative Financial Instruments.

Asset Retirement Obligations

        The Predecessor recognizes an estimated liability for future costs associated with the abandonment of its oil and natural gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired. The increase in carrying value is included in proved oil and natural gas properties in the accompanying consolidated and combined balance sheets. The Predecessor depletes the amount added to proved oil and natural gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties. For additional discussion, please refer to Note 10—Asset Retirement Obligations.

F-26

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)

Revenue Recognition

        The Predecessor derives revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when the Predecessor's production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Predecessor estimates the amount of production delivered to the purchaser and the price it will receive. The Predecessor follows the sales method of accounting for its oil and natural gas revenue, whereby revenue is recorded based on the Predecessor's share of volume sold, regardless of whether the Predecessor has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Predecessor has an imbalance on a specific property greater than the expected remaining proved reserves.

Incentive Units

        Incentive units are accounted for as liability awards under FASB ASC Topic 718, Compensation—Stock Compensation, with compensation expense based on period-end fair value. For additional discussion, please refer to Note 9—Incentive Unit Compensation.

Segment Reporting

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

Income Taxes

        Centennial OpCo is organized as a Delaware limited liability company, and Celero is organized as a Delaware limited partnership. As such, the Predecessor is treated as a flow-through entity for U.S. federal income tax purposes and for purposes of certain state and local income taxes. For such purposes, the net taxable income of the Predecessor and any related tax credits are passed through to the owners and are included in their tax returns, even though such net taxable income or tax credits may not have actually been distributed. Accordingly, no provision has been made in the consolidated and combined financial statements of the Predecessor for such income taxes paid at the owner level.

        The Predecessor is subject to the Texas franchise tax, at a statutory rate of 0.75% of taxable margin. Deferred tax assets and liabilities are recognized for future Texas franchise tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective Texas franchise tax bases. As of December 31, 2015 and 2014, the Predecessor's long-term deferred tax liability was $2.4 million and $2.9 million, respectively.

        The Predecessor evaluates the tax positions taken or expected to be taken in the course of preparing its tax returns and disallows the recognition of tax positions not deemed to meet a "more-likely-than-not" threshold of being sustained by the applicable tax authority. The Predecessor's management does not believe that any tax positions included in its tax returns would not meet this

F-27

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)

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

        As of December 31, 2015 the Predecessor has no current tax years under audit. The Predecessor remains subject to examination for federal income taxes and state income taxes for tax years 2012-2015.

Recently Issued Accounting Standards

        In May 2014, In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers. This guidance is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance. In August 2015, the FASB deferred the effective date of the new revenue recognition standard by one year. The revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Predecessor is currently evaluating the impact, if any, that the adoption of this update will have on its consolidated and combined financial statements or disclosures.

        In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. This update requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity's ability to continue as a going concern within one year after the date that the entity's financial statements are issued, or within one year after the date the entity's financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Predecessor is currently evaluating the impact, if any, that the adoption of this update will have on its consolidated and combined financial statements or disclosures.

        Effective November 1, 2015, the Predecessor early adopted, on a retrospective basis, ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires deferred financing costs to be presented on the accompanying consolidated and combined balance sheets as a direct deduction from the carrying value of the related debt liability. In accordance, the Predecessor has reclassified $0.4 million of deferred financing costs related to its term loan, from the Other noncurrent assets line item to the Term loan, net of unamortized deferred financing costs line item.

F-28

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)

The December 31, 2014 accompanying balance sheet line items that were adjusted as a result of the adoption of ASU No. 2015-03 are presented in the following table:

	As of December 31, 2014
	As Reported		As Adjusted
	(in thousands)
Other noncurrent assets	$	1,866	$	1,434
Total assets		616,201		615,769
Term loan		65,000		—
Term loan, net of unamortized deferred financing costs		—		64,568
Total liabilities		238,269		237,837
Total liabilities and owners' equity		616,201		615,769

        ASU 2015-03 does not specifically address the accounting for deferred financing costs related to line-of-credit arrangements. In August 2015, the FASB issued ASU No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements ("ASU 2015-15") allowing for deferred financing costs associated with line-of-credit arrangements to continue to be presented as assets. ASU 2015-15 is consistent with how the Predecessor currently accounts for deferred financing costs related to the Predecessor's revolving credit facility.

        Effective January 1, 2015, the Predecessor early adopted, on a prospective basis, ASU No. 2015-01, Income Statement—Extraordinary and Unusual Items. This ASU simplifies income statement presentation by eliminating the concept of extraordinary items. There was no impact to the Predecessor's consolidated and combined financial statements or disclosures from the adoption of this standard.

        Effective December 1, 2015, the Predecessor early adopted, on a prospective basis, ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes ("ASU 2015-17"). This ASU requires that deferred tax liabilities and assets, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendments in ASU 2015-17. As ASU 2015-17 was adopted on a prospective basis, the Predecessor did not retrospectively adjust prior periods.

F-29

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 3—Accounts Receivable and Accounts Payable and Accrued Expenses

        Accounts receivable are comprised of the following:

	December 31, 2015			December 31, 2014
	(in thousands)
Oil and natural gas	$	5,789		$	9,116
Joint interest billings		1,514			11,116
Hedge settlements		3,956			3,141
Other		1,844			—
Allowance for doubtful accounts		(91	)		(256	)
Accounts receivable, net	$	13,012		$	23,117

        Accounts payable and accrued expenses are comprised of the following:

	December 31, 2015		December 31, 2014
	(in thousands)
Accounts payable	$	1,827	$	30,224
Accrued capital expenditures		11,700		59,675
Revenues payable		3,439		7,566
Other		3,019		3,830
Accounts payable and accrued expenses	$	19,985	$	101,295

Note 4—Acquisitions and Divestitures

2015 Acquisitions

        On September 1, 2015, the Predecessor acquired additional interests in proved and unproved oil and natural gas properties in the Delaware Basin. Total cash consideration paid by the Predecessor was $16.0 million, net of closing adjustments.

        On September 3, 2015, the Predecessor acquired a non-operated interest in 1,804 net acres in the Delaware Basin from an unrelated third party. Total cash consideration paid by the Predecessor was $6.4 million, net of closing adjustments.

        The Predecessor determined that both of these acquisitions met the criteria for business combinations under FASB ASC Topic 805, Business Combinations. The Predecessor allocated the final purchase prices to the acquired assets and liabilities based on fair value as of the respective acquisition

F-30

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 4—Acquisitions and Divestitures (Continued)

dates, as summarized in the table below. Refer to Note 6—Fair Value Measurements for additional discussion on the valuation techniques used in determining the fair value of the acquired properties.

	Acquisition #1			Acquisition #2
	September 1, 2015			September 3, 2015
	(in thousands)
Cash consideration	$	16,006		$	6,369
Fair value of assets and liabilities acquired:
Proved oil and natural gas properties		7,731			6,491
Unproved oil and natural gas properties		8,312			—
Total fair value of oil and natural gas properties acquired		16,043			6,491
Asset retirement obligation		(37	)		(122	)
Total fair value of net assets acquired	$	16,006		$	6,369

2014 Acquisitions

        In June 2014, Centennial OpCo acquired 2,400 net acres in the Delaware Basin from an unrelated third party, for approximately $11.0 million, net of customary closing adjustments.

2014 Dispositions

        In December 2014, Centennial OpCo sold its interest in approximately 1,845 net acres in Ward County, Texas, including 18 vertical wells, to an NGP-controlled entity for proceeds of $12.5 million, which resulted in a gain of $1.5 million and was recorded as an equity contribution due to the entities being under common control.

        In May 2014, Celero sold its Caprock field to an unrelated third party for $59.3 million, net of customary closing adjustments. A net loss of $2.2 million was recognized on the sale during the second quarter of 2014.

        In February 2014, Centennial OpCo sold its 98.5% interest in Atlantic Midstream to PennTex Permian, an NGP-controlled entity for net proceeds of $71.8 million, which resulted in a gain of $20.0 million and was recorded as an equity contribution due to the entities being under common control.

2013 Acquisitions

        During the year ended December 31, 2013, the Predecessor acquired, from third-parties, a combination of new leases and additional working interest in wells it operates through a number of separate, individually insignificant transactions for aggregate consideration of $20.4 million. The Predecessor reflected the total consideration paid as $4.9 million of proved oil and natural gas properties and $15.5 million of unproved oil and natural gas properties.

F-31

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 4—Acquisitions and Divestitures (Continued)

2013 Divestitures

        In October 2013, the Predecessor sold non-operated oil and natural gas properties in its Wolfbone prospect for total proceeds of approximately $28.7 million, and realized a $7.7 million gain on sale.

        In August 2013, the Predecessor sold its interest in certain oil and natural gas properties, which covered 1,951 gross (1,617 net) acres in Midland County, Texas, including ten wells, for total proceeds of $17.1 million and realized a $7.9 million gain on sale.

        In June 2013, the Predecessor sold its interest in certain oil and natural gas properties, which covered 320 gross (187 net) acres in Glasscock and Midland Counties, Texas, including two wells, for total proceeds of $0.3 million, and realized a $0.3 million loss on sale.

Note 5—Derivative Financial Instruments

        The Predecessor has entered into various commodity derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Predecessor's derivative contracts include swap arrangements for oil.

        In a typical commodity swap agreement, if the agreed upon published third-party index price ("index price") is lower than the swap fixed price, the Predecessor receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Predecessor pays the difference. In addition, the Predecessor has entered into basis swap contracts in order to hedge the difference between the NYMEX index price and a local index price. When the actual differential exceeds the fixed price provided by the basis swap contract, the Predecessor receives the difference from the counterparty; when the differential is less than the fixed price provided by the basis swap contract, the Predecessor pays the difference to the counterparty.

        The Predecessor's derivative instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in the Predecessor's consolidated and combined statements of operations. The Predecessor's commodity derivatives are measured at fair value and are included in the accompanying consolidated and combined balance sheets as derivative assets. The fair value of the commodity contracts was a net asset of $21.1 million and $36.8 million as of December 31, 2015 and 2014, respectively.

        As of December 31, 2015, the Predecessor had open crude oil derivative positions with respect to future production as set forth in the table below. When aggregating multiple contracts, the weighted average contract price is disclosed.

	2016			2017
Crude Oil Swaps:
Notional volume (Bbl)		729,000			127,750
Weighted average floor price ($/Bbl)	$	67.82		$	61.36
Crude Oil Basis Swaps:
Notional volume (Bbl)		622,200			91,250
Weighted average floor price ($/Bbl)	$	(0.71	)	$	(0.20	)

F-32

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 5—Derivative Financial Instruments (Continued)

        The following table below summarizes the gross fair value of derivative assets and liabilities and the effect of netting on the consolidated and combined balance sheets (in thousands):

	Balance Sheet Classification	Gross Amounts		Netting Adjustments			Net Amounts Presented on the Balance Sheet
December 31, 2015:
Assets:
Derivative instruments	Current assets	$	19,469	$	(426	)	$	19,043
Derivative instruments	Noncurrent assets		2,071		(1	)		2,070
Total assets		$	21,540	$	(427	)	$	21,113
December 31, 2014:
Assets:
Derivative instruments	Current assets	$	30,444	$	(22	)	$	30,422
Derivative instruments	Noncurrent assets		6,365		—			6,365
Total assets		$	36,809	$	(22	)	$	36,787

        The following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for the periods presented (in thousands):

	For the Year Ended December 31,
	2015		2014		2013
Gain (loss) on derivative instruments	$	20,756	$	41,943	$	(4,410	)

Note 6—Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

        The Predecessor has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

        The following table is a listing of the Predecessor's assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of December 31, 2015:

	Level 1		Level 2		Level 3
Assets:
Derivative instruments, net(1)	$	—	$	21,113	$	—

(1)

This represents financial assets or liabilities that are measured at fair value on a recurring basis.

F-33

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 6—Fair Value Measurements (Continued)

        The following table is a listing of the Predecessor's assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of December 31, 2014:

	Level 1		Level 2		Level 3
Assets:
Derivative instruments, net(1)	$	—	$	36,787	$	—
Unproved oil and gas properties(2)	$	—	$	—	$	5,705

(1)

This represents a financial asset or liability that is measured at fair value on a recurring basis.

(2)

This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

        Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Predecessor as well as the general classification of such instruments pursuant to the above fair value hierarchy. There were no transfers between Level 1, Level 2 or Level 3 during any period presented.

Derivatives

        The Predecessor uses Level 2 inputs to measure the fair value of its derivative instruments. The fair value of all derivative instruments is estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The fair value of all derivative instruments is estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services, and the Predecessor has made no adjustments to the obtained prices. The independent pricing services publish observable market information from multiple brokers and exchanges. All valuations were compared against counterparty valuations to verify the reasonableness of prices. The Predecessor also considers counterparty credit risk and its own credit risk in its determination of all estimated fair values. The Predecessor has consistently applied these valuation techniques in all periods presented and believes it has obtained the most accurate information available for the types of derivative contracts it holds. The Predecessor recognizes transfers between levels at the end of the reporting period for which the transfer has occurred.

Nonrecurring Fair Value Measurements

        Unproved oil and natural gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of the unproved properties, the Predecessor uses a market approach, which takes into account further development plans, risk weighted potential resource recovery, and estimated reserve values (if any). The Predecessor recorded a $13.8 million impairment related to certain unproved oil and natural gas properties for the year ended December 31, 2014.

        The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that

F-34

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 6—Fair Value Measurements (Continued)

are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and natural gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Predecessor's management at the time of the valuation. Refer to Note 4—Acquisitions and Divestitures for additional information on the fair value of assets acquired.

Other Financial Instruments

        The carrying amounts of the Predecessor's cash, cash equivalents, accounts receivable, accounts payable, and accrued expenses approximate fair value due to the short-term maturities and/or liquid nature of these assets and liabilities. The carrying values of the amounts outstanding under the credit agreement approximate fair value because the variable interest rates are reflective of current market conditions.

Note 7—Long-Term Debt

Credit Agreement

        In May 2015, the Predecessor entered into an amendment to its amended and restated credit agreement ("credit agreement") dated as of October 15, 2014. The amendment extends the term loan maturity from April 15, 2017 to April 15, 2018. The credit agreement includes both a term loan commitment of $65.0 million (the "term loan") and a revolving credit facility (the "revolving credit facility") with commitments of $500.0 million (subject to the borrowing base), with a sublimit for letters of credit of $15.0 million. The borrowing base is subject to regular semi-annual redeterminations.

        The borrowing base of the revolving credit facility under the credit agreement is determined at the discretion of the lenders, and is subject to regular redeterminations in each quarter of 2015 and on April 1 and October 1 in subsequent years. The borrowing base depends on, among other things, the volumes of the Predecessor's proved oil and natural gas reserves and estimated cash flows from these reserves and the Predecessor's commodity hedge positions. In August 2015, the Predecessor's borrowing base was reaffirmed at $140.0 million. The next redetermination date is scheduled for April 1, 2016. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity were outstanding, the Predecessor could be forced to immediately repay a portion of its debt outstanding under the credit agreement.

        At December 31, 2015, outstanding borrowings under the revolving credit facility were $74.0 million and $0.6 million of outstanding letters of credit, leaving $65.4 million in borrowing capacity under the revolving credit facility.

        Interest on the term loan is LIBOR plus 5.25%. Borrowings under the credit agreement bear interest at either (i) LIBOR plus a margin between 1.50% and 2.50% or (ii) the prime rate plus a margin between 0.50% and 1.50%, in each case, based on the amount utilized. The annual commitment fee on the unused portion of the credit facility ranges between 0.375% and 0.50% based on the amount utilized.

F-35

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 7—Long-Term Debt (Continued)

        The Term loan, net of unamortized deferred financing costs line item on the accompanying consolidated and combined balance sheets as of December 31, 2015 and 2014, consisted of the following:

	December 31, 2015			December 31, 2014
	(in thousands)
Term loan	$	65,000		$	65,000
Unamortized deferred financing costs		(351	)		(432	)
Term loan, net of unamortized deferred financing costs	$	64,649		$	64,568

        The Predecessor must comply with certain financial and non-financial covenants under the terms of its credit agreement, including limitations on distribution payments, disposition of assets and requirements to maintain certain financial ratios, which include:

•

a requirement that the Predecessor's current assets—including amounts available to be drawn under the credit agreement—must exceed current liabilities;

•

a requirement that the Predecessor maintain a ratio of consolidated funded debt to consolidated EBITDAX of not more than 4.0 to 1.0.

        At December 31, 2015 the Predecessor was in compliance with its financial covenants.

Note 8—Owners' Equity

Centennial OpCo

        Centennial OpCo's operations are governed by the provisions of the Fourth Amended and Restated Limited Liability Company Agreement ("Agreement"), effective April 15, 2015. As of December 31, 2015, members included Centennial HoldCo, Celero and Follow-On, owning an approximate 61.2%, 21.2% and 17.6% membership interest in Centennial OpCo, respectively.

        In 2015 Follow-On contributed $84.2 million to Centennial OpCo in exchange for membership interests in Centennial OpCo. In addition, Centennial HoldCo contributed approximately $27.2 million to Centennial OpCo in exchange for additional membership interests in Centennial OpCo.

        At December 31, 2015, Centennial OpCo has two classes of membership interests outstanding: Class A, which consist of membership interests held by Centennial HoldCo and Follow-On; and Class B, which consist of membership interests held by Celero. As of December 31, 2015, Centennial HoldCo had contributed $289.4 million and had a remaining capital commitment of $32.5 million, Follow-On had contributed $84.2 million and had a remaining capital commitment of $100.3 million, and Celero had contributed $125.4 million in conjunction with the Combination and does not have a remaining capital commitment. Under the terms of the Agreement, Centennial OpCo will dissolve upon the earlier of July 1, 2022; the sale, disposition or termination of all or substantially all of the property owned by Centennial OpCo; or consent in writing of Centennial HoldCo. Pursuant to the Agreement (and as is customary for limited liability companies), the liability of the members is limited to their contributed capital.

F-36

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 8—Owners' Equity (Continued)

        In December 2014, the Predecessor sold its interest in approximately 1,845 net acres in Ward County, Texas, including 18 vertical wells, to an NGP-controlled entity for proceeds of $12.5 million. Because the Predecessor and purchaser are considered entities under common control, the gain of $1.5 million was recorded as a deemed contribution from sale of assets.

        On October 15, 2014, Celero conveyed substantially all of its oil and gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo. In connection with the transaction Centennial HoldCo made cash tender offers to Celero's limited partners to purchase their interest in the Partnership for their respective share of the transaction value of $157.6 million. A total of 20.4% of the partners accepted the cash tender offer for a total of $32.2 million. Celero subsequently redeemed Celero limited partnership interests from Centennial HoldCo for $17.1 million in cash and $15.1 million in Centennial OpCo's membership interest. Celero's contribution in Centennial OpCo after the conveyance was $125.4 million. Furthermore, the Combination was accounted for as a reorganization of entities under common control in a manner similar to a pooling of interest which resulted in a deemed distribution of $4.1 million.

        On April 30, 2014 NGP X contributed and conveyed its membership interest in Centennial OpCo to Centennial HoldCo. On May 9, 2014, Centennial OpCo's remaining members sold their membership interests to Centennial OpCo for $75.7 million.

        On March 31, 2014 all of Centennial OpCo's employee members sold their membership interests in Centennial OpCo. Centennial OpCo paid $11.4 million, net of promissory notes from certain employee members, to acquire the membership interests. Contemporaneously, Centennial HoldCo, agreed to purchase the entirety of Centennial OpCo's issued and outstanding incentive units. The total consideration paid by Centennial HoldCo to acquire the issued and outstanding incentive units was $12.4 million and is included in General and administration expense on the consolidated and combined statement of operations. Additionally, the Predecessor recorded a deemed contribution from parent for payment of incentive units from Centennial HoldCo of $12.4 million for funding the incentive unit purchase. All of the incentive unit purchases were fully settled and terminated as of August 31, 2014.

        In February 2014, the Predecessor sold its 98.5% interest in Atlantic Midstream to PennTex Permian, an NGP-controlled entity for net proceeds of $71.8 million. Because the Predecessor and purchaser are considered entities under common control, the gain of $20.0 million was recorded as a deemed contribution from sale of assets.

        In 2013, Centennial OpCo accepted $3.4 million of capital contributions from certain employee members in exchange for full recourse promissory notes, which were recorded as a reduction of owners' equity.

Celero

        In 2014, a portion of limited partners of the partnership elected to exit the partnership for total consideration of $32.2 million. In 2013, Celero made a $21.1 million tax distribution.

F-37

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 9—Incentive Unit Compensation

Follow-On Incentive Units

        Under the Amended and Restated NGP Centennial Follow-On LLC Agreement ("Follow-On LLC Agreement"), Follow-On grants certain incentive units to certain employees of Centennial Resource Management, LLC ("Centennial Management"), a wholly-owned subsidiary of Centennial HoldCo. Employees of Centennial Management provide substantially all of their services to the Predecessor and in substance the incentive unit holders are employees of the Predecessor; therefore, Follow-On's incentive units have been treated as obligations of the Predecessor for accounting purposes.

        In April 2015, Tier I, Tier II, Tier III, Tier IV and Tier V incentive units were issued.

        The following table summarizes Follow-On's incentive unit activity for the year ended December 31, 2015:

	Tier I			Tier II			Tier III			Tier IV			Tier V
Incentive units at December 31, 2014		—			—			—			—			—
Forfeited		(5,000	)		(5,000	)		(5,000	)		(5,000	)		(5,000	)
Granted		919,000			919,000			919,000			919,000			919,000
Incentive units at December 31, 2015		914,000			914,000			914,000			914,000			914,000
Vested at December 31, 2015		121,197			121,197			—			—			—

        All of the incentive units are non-voting and subject to certain vesting and performance conditions. The terms of the incentive units are as follows: Tier I and Tier II incentive units vest ratably over five years, but are subject to forfeiture if payout is not achieved. In addition, all unvested Tier I and Tier II incentive units vest immediately upon Tier I and Tier II payout, respectively. Tier III, IV and V incentive units vest only upon the achievement of certain payout thresholds for each such tier and each tier of incentive units is subject to forfeiture if the applicable required payouts are not achieved. In addition, vested and unvested incentive units are forfeited if an incentive unit holder's employment is terminated for any reason or if the incentive unit holder voluntarily terminates their employment. Payouts for each Tier I through V are based upon achievement of specified rates of return on Follow-On's invested capital.

        The incentive units are issued to employees in return for services provided and cash payout is based, in part, on the value of Follow-On's equity; therefore, the incentive units are accounted for as liability awards under FASB ASC Topic 718, Compensation—Stock Compensation, with compensation expense based on period-end fair value. The achievement of payout conditions is a performance condition that requires the Predecessor to assess, at each reporting period, the probability that an event of payout will occur. Compensation cost is required to be recognized at such time that the payout terms are probable of being met. No incentive compensation expense was recorded at December 31, 2015 or 2014, because it was not probable that the performance criterion would be met.

Centennial HoldCo Incentive Units

        As of December 31, 2015 and 2014, Tier I, Tier II, Tier III, Tier IV and Tier V incentive units had been issued to certain employees of Centennial Management. Employees of Centennial Management provide substantially all of their services to the Predecessor and in substance the incentive unit holders

F-38

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 9—Incentive Unit Compensation (Continued)

are employees of the Predecessor. Therefore, Centennial HoldCo's incentive units have been treated as obligations of the Predecessor for accounting purposes.

        The following table summarizes Centennial HoldCo's incentive unit activity for the years ended December 31, 2015 and 2014:

	Tier I			Tier II			Tier III			Tier IV			Tier V
Incentive units at December 31, 2013		655,000			655,000			655,000			655,000			655,000
Forfeited		—			—			—			—			—
Granted		254,000			254,000			254,000			254,000			254,000
Incentive units at December 31, 2014		909,000			909,000			909,000			909,000			909,000
Forfeited		(6,000	)		(6,000	)		(6,000	)		(6,000	)		(6,000	)
Granted		11,000			11,000			11,000			11,000			11,000
Incentive units at December 31, 2015		914,000			914,000			914,000			914,000			914,000
Vested at December 31, 2015		370,517			370,517			—			—			—

        All of the incentive units are non-voting and subject to certain vesting and performance conditions. The terms of the incentive units are as follows: Tier I and Tier II incentive units vest ratably over five years, but are subject to forfeiture if payout is not achieved. In addition, all unvested Tier I and Tier II incentive units vest immediately upon Tier I and Tier II payout, respectively. Tier III, IV and V incentive units vest only upon the achievement of certain payout thresholds for each such tier and each tier of incentive units is subject to forfeiture if the applicable required payouts are not achieved. In addition, vested and unvested incentive units are forfeited if an incentive unit holder's employment is terminated for any reason or if the incentive unit holder voluntarily terminates their employment. Payouts for each Tier I through Tier V are based upon achievement of specified rates of return on Centennial HoldCo's invested capital.

        The incentive units are issued to employees in return for services provided and cash payout is based, in part, on the value of Centennial HoldCo's equity; therefore, the incentive units are accounted for as liability awards under FASB ASC Topic 718, Compensation—Stock Compensation, with compensation expense based on period-end fair value. The achievement of payout conditions is a performance condition that requires the Predecessor to assess, at each reporting period, the probability that an event of payout will occur. Compensation cost is required to be recognized at such time that the payout terms are probable of being met. No incentive compensation expense was recorded at December 31, 2015 or 2014, because it was not probable that the performance criterion would be met.

Centennial OpCo Incentive Units

        Under Centennial OpCo's Second Amended and Restated Limited Liability Company Agreement, Centennial OpCo issued certain incentive units to its management and employees. All of the incentive units were non-voting and subject to certain vesting and performance conditions. The incentive units were accounted for as liability awards and compensation expense is based on period-end fair value.

        On March 31, 2014, Centennial HoldCo agreed to purchase the entirety of Centennial OpCo's issued and outstanding incentive units for total consideration of $12.4 million (the "Incentive Unit

F-39

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 9—Incentive Unit Compensation (Continued)

Purchase"). The closing and funding of the Incentive Unit Purchase occurred separately for each employee in accordance with each individual Membership Interest Purchase Agreement during the second and third quarters of 2014 and is included within the General and administrative expense line item in the consolidated and combined statements of operations for the year ended December 31, 2014. Additionally, the Predecessor recorded a capital contribution from Centennial HoldCo of $12.4 million for funding of the Incentive Unit Purchase during the year ended December 31, 2014. As a result of the Incentive Unit Purchase, all of Centennial OpCo's incentive units were fully settled and terminated as of August 31, 2014.

        The following table summarizes Centennial OpCo's incentive unit activity for the years ended December 31, 2014 and 2013:

	Tier I			Tier II			Tier III			Tier IV			Tier V
Incentive units at December 31, 2012		941,252			—			935,004			939,137			939,137
Forfeited		(4,557	)		(1,519	)		(4,557	)		—			—
Settled		(132,322	)		(132,322	)		(132,322	)		(136,681	)		(136,681	)
Granted		45,877			984,091			45,865			45,893			45,893
Incentive units at December 31, 2013		850,250			850,250			843,990			848,349			848,349
Forfeited		—			—			—			—			—
Settled		(866,159	)		(866,159	)		(843,990	)		(848,349	)		(848,349	)
Granted		15,909			15,909			—			—			—
Incentive units at December 31, 2014		—			—			—			—			—

Note 10—Asset Retirement Obligations

        The Predecessor recognizes an estimated liability for future costs associated with the plugging and abandonment of its oil and natural gas properties. A liability for the fair value of an asset retirement obligation ("ARO") and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired. The increase in carrying value is included in proved oil and natural gas properties in the accompanying consolidated and combined balance sheets. The Predecessor depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties. Cash paid to settle asset retirement obligations is included in the operating section of the Predecessor's accompanying consolidated and combined statements of cash flows.

        The Predecessor's estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In periods subsequent to the initial measurement of the ARO, the Predecessor must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows.

F-40

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 10—Asset Retirement Obligations (Continued)

        The following table summarizes the changes in the Predecessor's asset retirement obligations for the periods indicated (in thousands):

	For the Year Ended December 31,
	2015		2014
Asset retirement obligations, beginning of year	$	1,824	$	3,557
Additional liabilities incurred		133		670
Liabilities acquired		178		—
Liabilities disposed(1)		—		(2,820	)
Accretion expense		139		156
Revision of estimated liabilities		14		261
Asset retirement obligations, end of year	$	2,288	$	1,824

(1)

Refer to Note 4—Acquisitions and Divestitures.

Note 11—Commitments and Contingencies

Commitments

        The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2015:

Years Ending December 31,	Amount
	(in thousands)
2016	$	2,676
2017		477
2018		485
2019		419
2020		—
Thereafter		—
Total	$	4,057

Drilling Rig Contracts

        As of December 31, 2015, the Predecessor is not party to any long-term drilling rig contracts.

        In light of the low commodity price environment, the Predecessor curtailed its drilling activity during 2015. For the year ended December 31, 2015, the Predecessor incurred drilling rig termination fees of $2.4 million, which are recorded in the Contract termination and rig stacking line item in the accompanying consolidated and combined statement of operations.

F-41

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 11—Commitments and Contingencies (Continued)

Office Leases

        The Predecessor leases office space in Denver, Colorado and Midland, Texas. Rent expense for the years ended December 31, 2015, 2014 and 2013 was $0.4 million, $0.5 million and $0.8 million, respectively.

Financing Obligation

        The Predecessor is party to a contract with PennTex Permian, LLC ("PennTex"), an NGP-controlled entity, to construct an expansion of the gathering system and a receipt point. The Predecessor will reimburse the gas gatherer for the total cost of the expansion project. The Predecessor shall pay a minimum fee of $7,000 per day until the gas gatherer recoups the capital outlay for the expansion project. The Predecessor determined that the agreement contains an embedded lease and the transaction was accounted for as a financing obligation. The Predecessor recorded an asset and a liability of $3.8 million attributable to this agreement. The asset is being depreciated over its estimated remaining life. At December 31, 2015, a short-term liability of $2.1 million was included in Other current liabilities on the consolidated and combined balance sheets. The Predecessor has made payments of $1.7 million as of December 31, 2015, including interest.

Contingencies

        The Predecessor is subject to litigation and claims arising in the ordinary course of business. The Predecessor accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such pending litigation and claims will not have a material effect on the results of operations, the financial position, or the cash flows of the Predecessor.

Note 12—Transactions with Related Parties

        In December 2014, the Predecessor sold its interest in approximately 1,845 net acres in Ward County, Texas, including 18 vertical wells, to an NGP-controlled entity for proceeds of $12.5 million. For additional discussion, please refer to Note 4—Acquisitions and Divestitures.

        In October 2014, Celero, an NGP-controlled entity, conveyed substantially all of its oil and gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo. As a result of the transaction, Centennial HoldCo owned approximately 72% of Centennial OpCo, and Celero owned the remaining 28%. For additional discussion, please refer to Note 2—Basis of Presentation.

        Effective October 14, 2014, the Predecessor entered into a Management Services Agreement with Centennial Management, a wholly-owned subsidiary of Centennial HoldCo. Employees of Centennial Management provide substantially all of their services to the Predecessor.

        In October 2014, the gas gathering agreement with PennTex Permian was amended to construct an expansion of the gathering system and a receipt point. The Predecessor will reimburse PennTex Permian for the total cost of the expansion project. The Predecessor shall pay a minimum fee of $7,000 per day until PennTex Permian recoups the capital outlay for the expansion project. At December 31, 2015, a short-term liability of $2.1 million was included in Other current liabilities on the consolidated

F-42

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 12—Transactions with Related Parties (Continued)

and combined balance sheets. As of December 31, 2015, the Predecessor has made payments of $1.7 million, including interest.

        In February 2014, the Predecessor entered into a gas gathering agreement with Atlantic Midstream. At the time this agreement was entered into, the Predecessor had a 98.5% interest in Atlantic Midstream. In February 2014, subsequent to entry into this gas gathering agreement, the Predecessor sold its 98.5% interest in Atlantic Midstream to PennTex Permian, LLC, an NGP-controlled entity for net proceeds of $71.8 million. PennTex paid the Predecessor $1.2 million and $2.2 million for purchases of residue gas and NGLs (net of gathering, processing and other fees) for the years ended December 31, 2015 and 2014.

        From time to time, the Predecessor obtains services related to its drilling and completion activities from affiliates of NGP. In particular, since 2014, the Predecessor has paid the following amounts to the following affiliates of NGP for such services: (i) approximately $1.2 million during the year ended December 31, 2015 to RockPile Energy Services, LLC; and (ii) approximately $1.7 million during the year ended December 31, 2014 to MS Energy Services.

Note 13—Subsequent Events

        The Predecessor has evaluated all subsequent events through April 4, 2016, the date the financial statements were issued and has nothing additional to disclose.

Note 14—Supplemental Oil and Gas Information (unaudited)

Costs Incurred For Oil and Natural Gas Producing Activities

        The following table sets forth the capitalized costs incurred in the Predecessor's oil and natural gas production, exploration, and development activities:

	For the Years Ended December 31,
	2015		2014		2013
	(in thousands)
Acquisition costs:
Proved properties	$	14,268	$	5,758	$	10,208
Unproved properties		28,955		16,409		17,204
Development costs		87,452		324,802		151,562
Total	$	130,675	$	346,969	$	178,974

Oil and Gas Reserve Quantities

        The reserve estimates presented below were made in accordance with U.S. GAAP requirements for disclosures about oil and natural gas producing activities and Securities and Exchange Commission ("SEC") rules for oil and natural gas reporting reserves estimation and disclosure.

F-43

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 14—Supplemental Oil and Gas Information (unaudited) (Continued)

        Estimates of the Predecessor's proved oil and natural gas reserves at December 31, 2015 and 2014 were prepared by Netherland, Sewell & Associates, Inc. Estimates of the Predecessor's proved oil and natural gas reserves at December 31, 2013 were prepared internally by management and not by independent third-party petroleum engineers.

        There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

        The following table summarizes the trailing 12-month index prices used in the reserve estimates for the years ended December 31, 2015, 2014 and 2013. The following prices, as adjusted for transportation, quality, and basis differentials, were used in the calculation of the standardized measure of discounted future net cash flows ("standardized measure"):

	For the Years Ended December 31,
	2015		2014		2013
	(in thousands)
Oil (per Bbl)	$	41.85	$	84.94	$	92.05
Gas (per Mcf)	$	1.71	$	4.70	$	3.76
NGLs (per Bbl)	$	13.94	$	22.70	$	26.05

F-44

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 14—Supplemental Oil and Gas Information (unaudited) (Continued)

        The table below presents a summary of changes in the Predecessor's estimated proved reserves:

	For the Years Ended December 31,
	2015									2014									2013
	Crude Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Crude Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Crude Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)
Total Proved Reserves:
Beginning of the year		19,850			27,414			1,551			18,510			6,968			525			11,422			10,032			967
Extensions and discoveries		9,444			11,927			1,432			16,122			22,575			1,127			12,459			5,189			300
Revisions of previous estimates		(5,109	)		(5,204	)		995			56			178			180			426			837			80
Purchases of reserves in place		844			1,363			204			162			192			23			109			94			8
Divestitures of reserves in place		—			—			—			(13,572	)		(387	)		(69	)		(5,193	)		(8,387	)		(732	)
Production		(1,830	)		(3,058	)		(331	)		(1,428	)		(2,112	)		(235	)		(713	)		(797	)		(98	)
End of the year		23,199			32,442			3,851			19,850			27,414			1,551			18,510			6,968			525
Proved Developed Reserves:
Beginning of the year		8,026			11,959			766			6,021			4,837			382			2,978			2,078			285
End of the year		9,347			12,711			1,603			8,026			11,959			766			6,021			4,837			382
Proved Undeveloped Reserves:
Beginning of the year		11,823			15,455			785			12,489			2,131			143			8,444			7,954			682
End of the year		13,852			19,731			2,248			11,823			15,455			785			12,489			2,131			143

        Proved reserves at December 31, 2015 increased 25% to 32,457 MBoe, compared to 25,970 MBoe at December 31, 2014.

        During 2015, the Predecessor added 12,864 MBoe of proved reserves through extensions, primarily due to its drilling activity.

        During 2015, the Predecessor had net negative revisions of 4,981 MBoe. The significant decrease in commodity prices seen in 2015 resulted in negative revisions related to the conversion of approximately 6,794 MBoe from PUDs to unproved reserves, partially offset by a positive revision in performance.

        During 2015, the Predecessor acquired 1,275 MBoe of proved reserves. Refer to Note 4—Acquisitions and Divestitures.

        During 2014, the Predecessor added 21,012 MBoe of proved reserves through extensions and discoveries, primarily due to its continued development drilling program and 265 MBoe of proved reserves, due to better than expected performance of its proved developed reserves.

        During 2014, the Predecessor divested of 13,706 MBoe of proved reserves. Refer to Note 4—Acquisitions and Divestitures.

        During 2013, the Predecessor added 6,934 MBoe of proved reserves through extension and discoveries, primarily from the drilling of new wells and from new proved undeveloped locations added during the year. Additionally, the Predecessor added 6,799 MBoe through improved recovery. Improved

F-45

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 14—Supplemental Oil and Gas Information (unaudited) (Continued)

recovery reflects reserve additions that result from the application of tertiary recovery methods such as CO₂ injection at the Predecessor's Caprock field. The Caprock field was sold in May 2014.

        During 2013, the Predecessor had revisions of 646 MBoe due to better than expected performance attributable to its proved developed reserves.

        During 2013, the Predecessor divested of 7,323 MBoe for certain properties sold. Refer to Note 4—Acquisitions and Divestitures.

Standardized Measure of Discounted Future Net Cash Flows

        The Predecessor computes a standardized measure of discounted future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

        Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions.

        The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Predecessor's expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process.

        The following table presents the Predecessor's standardized measure of discounted future net cash flows for the periods indicated:

	December 31,
	2015			2014			2013
	(in thousands)
Future cash inflows	$	1,079,962		$	1,850,205		$	1,743,612
Future development costs		(277,837	)		(440,366	)		(223,227	)
Future production costs		(450,058	)		(457,236	)		(601,614	)
Future income tax expenses		(6,643	)		(10,834	)		(3,540	)
Future net cash flows		345,424			941,769			915,231
10% discount to reflect timing of cash flows		(210,355	)		(575,886	)		(543,924	)
Standardized measure of discounted future net cash flows	$	135,069		$	365,883		$	371,307

F-46

CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)

Note 14—Supplemental Oil and Gas Information (unaudited) (Continued)

        A summary of changes in the standardized measure of discounted future net cash flows is as follows for the periods indicated:

	For the Years Ended December 31,
	2015			2014			2013
	(in thousands)
Standardized measure of discounted future net cash flows, beginning of the period	$	365,883		$	371,307		$	257,083
Sales of oil, natural gas and NGLs, net of production costs		(58,534	)		(102,488	)		(47,424	)
Purchase of minerals in place		14,416			5,650			4,410
Divestiture of minerals in place		—			(242,344	)		(73,174	)
Extensions and discoveries, net of future development costs		57,894			312,532			99,107
Change in estimated development costs		16,100			10,386			7,520
Net change in prices and production costs		(494,734	)		(3,027	)		21,601
Change in estimated future development costs		247,642			2,935			(40,783	)
Revisions of previous quantity estimates		(51,342	)		924			135,759
Accretion of discount		37,517			13,561			19,000
Net change in income taxes		1,601			(2,762	)		(35	)
Net change in timing of production and other		(1,374	)		(791	)		(11,757	)
Standardized measure of discounted future net cash flows, end of the period	$	135,069		$	365,883		$	371,307

F-47

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED
FINANCIAL INFORMATION

        The unaudited pro forma condensed consolidated combined statements of operations for the nine months ended September 30, 2016 and for the year ended December 31, 2015 combine the historical consolidated statements of operations of Silver Run Acquisition Corporation ("Silver Run") and the historical consolidated statements of operations of Centennial Resource Production, LLC, a Delaware limited liability company ("CRP"), giving effect to the Transactions (as defined below) as if they had been consummated on January 1, 2015, the beginning of the earliest period presented. The unaudited pro forma condensed consolidated combined balance sheet as of September 30, 2016 combines the historical consolidated balance sheet of Silver Run and the historical condensed consolidated balance sheet of CRP, giving effect to the following transactions (for purposes of this section, collectively, the "Transactions") as if they had been consummated on September 30, 2016:

•

the acquisition by Silver Run of approximately 89% of the outstanding membership interests in CRP pursuant to 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 controlled by Riverstone Investment Group LLC and its affiliates (collectively, "Riverstone"), to which we expect to become a party following the approval and adoption of the same by Silver Run's stockholders (the "business combination");

•

the conversion of 12,500,000 shares of Silver Run's Class B Common Stock, par value $0.0001 per share, into 12,500,000 shares of Silver Run's Class A Common Stock, par value $0.0001 per share (the "Class A Common Stock"), in connection with the business combination;

•

the issuance by Silver Run of 20,000,000 shares of a new class of capital stock designated as Class C Common Stock, par value $0.0001 per share (the "Class C Common Stock"), to the Centennial Contributors in connection with the business combination;

•

the issuance by Silver Run of 1 share of a new class of preferred stock designated as Series A Preferred Stock, par value $0.0001 per share (the "Series A Preferred Stock"), to CRD in connection with the business combination;

•

the issuance and sale by Silver Run of (a) up to 81,005,000 shares of Class A Common Stock to Riverstone Centennial Holdings, L.P, an accredited investor affiliated with Riverstone (together with any person to whom it assigns the right to purchase such shares, the "Riverstone private investors" and such issuance, together with any issuance of additional shares of Class A Common Stock to the Riverstone private investors to facilitate the Transactions, the "Riverstone Private Placement"), and (b) 20,000,000 shares of Class A Common Stock to certain other accredited investors in a private placement (together with the Riverstone Private Placement, the "Private Placements"), the proceeds of which will be used to fund a portion of the cash consideration in the business combination;

•

the contribution of cash by Silver Run to CRP necessary for CRP to repay any of its or its subsidiaries' outstanding debt that becomes due and payable as a result of the consummation of the business combination, which as of September 30, 2016, was approximately $189.0 million (the "Additional Debt Repayment Contribution"); and

•

the redemption by Silver Run of shares of Class A Common Stock held by any public stockholders in connection with the business combination and the issuance by Silver Run of

F-48

additional shares of Class A Common Stock to the Riverstone private investors to offset such redemptions on a share-for-share basis.

        The historical consolidated financial statements have been adjusted in the unaudited pro forma condensed consolidated combined financial statements to give pro forma effect to events that are: (1) directly attributable to the business combination; (2) factually supportable; and (3) with respect to the statement of operations, expected to have a continuing impact on Silver Run's results following the completion of the Transactions.

        The unaudited pro forma condensed consolidated combined financial statements have been developed from and should be read in conjunction with:

•

the accompanying notes to the unaudited pro forma condensed consolidated combined financial statements;

•

the historical audited financial statements of Silver Run as of December 31, 2015 and for the period from November 4, 2015 (date of inception) to December 31, 2015, which are included in Silver Run's definitive proxy statement filed with the Securities and Exchange Commission (the "SEC") on September 23, 2016 (the "Proxy Statement");

•

the historical unaudited financial statements of Silver Run as of and for the three and nine months ended September 30, 2016, which are included in Silver Run's Form 10-Q for the quarter ended September 30, 2016 filed with the SEC on November 10, 2016 (the "Silver Run 10-Q");

•

the historical consolidated audited financial statements of CRP as of and for the year ended December 31, 2015, which are included in the Proxy Statement;

•

the historical condensed consolidated unaudited financial statements of CRP as of and for the nine months ended September 30, 2016, which are included within this registration statement; and

•

other information relating to Silver Run and CRP contained in the Proxy Statement.

        Under Silver Run's amended and restated certificate of incorporation, public stockholders have the right to redeem, upon the closing of the business combination, shares of Class A Common Stock then held by them for cash equal to their pro rata share of the aggregate amount on deposit (as of two business days prior to the closing of the business combination) in the Trust Account. For illustrative purposes, based on the fair value of marketable securities held in the Trust Account as of September 30, 2016 of approximately $500,549,792, the estimated per share redemption price would have been approximately $10.00. To the extent that any shares of Class A Common Stock are redeemed from the public stockholders, the Riverstone private investors have agreed to be ready, willing and able to purchase additional shares of Class A Common Stock from us at $10.00 per share to offset such redemptions on a share-for-share basis. As a result, if we assume as an illustrative redemption scenario that approximately 47.9 million shares of Class A Common Stock are redeemed from the public stockholders, resulting in an aggregate payment of $478.8 million from the Trust Account, the reduction in the Trust Account of $478.8 million is assumed to result in Silver Run issuing approximately an additional 47.9 million shares of Class A Common Stock to the Riverstone private investors as part of the Riverstone Private Placement, and the illustrative redemption scenario does not result in any pro forma adjustments to the unaudited pro forma condensed consolidated combined balance sheet or the cash and cash equivalents, common stock, additional paid in capital, pro forma shares outstanding or earnings per share line items.

        The unaudited pro forma condensed consolidated combined financial statements have been prepared using the acquisition method of accounting in accordance with U.S. GAAP with Silver Run as

F-49

the acquirer. Under the acquisition method of accounting, the purchase price is allocated to the underlying CRP assets acquired and liabilities assumed based on their respective fair market values.

        Silver Run has not completed the detailed valuation studies necessary to arrive at the required estimates of the fair value of the assets acquired, the liabilities assumed and the related allocations of the purchase price in the business combination. As a result, the unaudited pro forma adjustments are preliminary and are subject to change as additional information becomes available and as additional analyses are performed. The unaudited pro forma adjustments have been made solely for the purpose of providing the unaudited pro forma condensed consolidated combined financial statements presented below.

        Silver Run has estimated the fair value of assets acquired and liabilities assumed based on discussions with members of CRP's management, preliminary valuation studies, due diligence and information presented in the financial statements and accounting records of CRP. The valuation will be finalized as soon as practicable within the required measurement period, but in no event later than twelve months following completion of the business combination. Any increases or decreases in the fair value of these assets and liabilities upon completion of the final valuations will result in adjustments to the balance sheet and/or statement of operations. In addition, the final purchase price of the business combination is subject to the final determination of the Additional Debt Repayment Contribution. The final purchase price and the final purchase price allocation may be different than that reflected in the preliminary purchase price allocation presented herein, and this difference may be material.

        Assumptions and estimates underlying the unaudited pro forma adjustments set forth in the unaudited pro forma condensed consolidated combined financial statements are described in the accompanying notes. The unaudited pro forma condensed consolidated combined financial statements have been presented for illustrative purposes only and are not necessarily indicative of the operating results and financial position that would have been achieved had the business combination and the other related Transactions occurred on the dates indicated. Further, the unaudited pro forma condensed consolidated combined financial statements do not purport to project the future operating results or financial position of Silver Run following the completion of the business combination and the other related Transactions. The unaudited pro forma adjustments represent management's estimates based on information available as of the date of these unaudited pro forma condensed consolidated combined financial statements and are subject to change as additional information becomes available and analyses are performed.

F-50

Silver Run Acquisition Corporation

Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations

Year Ended December 31, 2015

(in thousands)

	(a) Silver Run			(b) CRP			Pro forma Adjustments				Pro forma Combined (Assuming No Redemptions and Assuming Illustrative Redemptions)
Revenues
Oil sales	$	—		$	77,643		$	—			$	77,643
Natural gas sales		—			7,965			—				7,965
NGL sales		—			4,852			—				4,852
Total revenues		—			90,460			—				90,460
Operating expenses
Lease operating expenses		—			21,173			—				21,173
Severance and ad valorem taxes		—			5,021			—				5,021
Transportation, processing, gathering and other operating expenses		—			5,732			—				5,732
Depreciation, depletion, amortization and accretion of asset retirement obligations		—			90,084			(24,338	)	(c)		65,746
Abandonment expense and impairment of unproved properties		—			7,619			—				7,619
Exploration		—			84			—				84
Contract termination and rig stacking		—			2,387			—				2,387
General and administrative expenses		2			14,206			—				14,208
Total operating expenses		2			146,306			(24,338	)			121,970
Gain on sale of oil and natural gas properties		—			(2,439	)		—				(2,439	)
Total operating loss		(2	)		(53,407	)		24,338				(29,071	)
Other (expense) income
Interest expense		—			(6,266	)		5,089		(e)		(1,177	)
Other income		—			20			—				20
Gain on derivative instruments		—			20,756			—				20,756
Total other income		—			14,510			5,089				19,599
(Loss) income before income taxes		(2	)		(38,897	)		29,427				(9,472	)
Income tax benefit		—			572			2,459		(f)		3,031
Net (loss) income		(2	)		(38,325	)		31,886				(6,441	)
Less: Net loss attributable to non-controlling interests		—			—			(1,032	)	(g)		(1,032	)
Net (loss) income attributable to the combined entity	$	(2	)	$	(38,325	)	$	32,918			$	(5,409	)
Net loss per common share
Basic	$	0.00									$	(0.03	)	(h)
Diluted	$	0.00									$	(0.03	)	(h)
Weighted average common shares outstanding
Basic		12,938										163,500		(h)
Diluted		12,938										183,500		(h)

F-51

Silver Run Acquisition Corporation

Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations

Nine Months Ended September 30, 2016

(in thousands)

	(a) Silver Run			(b) CRP			Pro forma Adjustments				Pro forma Combined (Assuming No Redemptions and Assuming Illustrative Redemptions)
Revenues
Oil sales	$	—		$	56,975		$	—			$	56,975
Natural gas sales		—			5,717			—				5,717
NGL sales		—			3,097			—				3,097
Total revenues		—			65,789			—				65,789
Operating expenses
Lease operating expenses		—			10,295			—				10,295
Severance and ad valorem taxes		—			3,523			—				3,523
Transportation, processing, gathering and other operating expenses		—			4,375			—				4,375
Depreciation, depletion, amortization and accretion of asset retirement obligations		—			60,939			(26,440	)	(c)		34,499
Abandonment expense and impairment of unproved properties		—			2,546			—				2,546
General and administrative expenses		1,009			10,655			—				11,664
Total operating expenses		1,009			92,333			(26,440	)			66,902
Gain on sale of oil and natural gas properties		—			11			—				11
Total operating income (loss)		(1,009	)		(26,533	)		26,440				(1,102	)
Other (expense) income
Interest expense		—			(5,422	)		4,587		(e)		(835	)
Other income—investment income on Trust Account		550			—			(550	)	(d)		—
Other income		—			6			—				6
Loss on derivative instruments		—			(4,184	)		—				(4,184	)
Total other income (expense)		550			(9,600	)		4,037				(5,013	)
Income (loss) before income taxes		(459	)		(36,133	)		30,477				(6,115	)
Income tax benefit		—			406			1,522				1,928		(f)
Net income (loss)		(459	)		(35,727	)		31,999				(4,187	)
Less: Net loss attributable to non-controlling interests		—			—			(657	)			(657	)	(g)
Net income (loss) attributable to the combined entity	$	(459	)	$	(35,727	)	$	32,656			$	(3,530	)
Net loss per common share
Basic	$	(0.03	)								$	(0.02	)	(h)
Diluted	$	(0.03	)								$	(0.02	)	(h)
Weighted average common shares outstanding
Basic		14,328										163,500		(h)
Diluted		14,328										183,500		(h)

F-52

Silver Run Acquisition Corporation

Unaudited Pro Forma Condensed Consolidated Combined Balance Sheet

At September 30, 2016

(in thousands)

	(a) Silver Run			(b) CRP			Pro forma Adjustments				Pro forma Combined (Assuming No Redemptions and Assuming Illustrative Redemptions)
ASSETS
Current assets
Cash and cash equivalents	$	138		$	410		$	99,806		(c)	$	100,354
Accounts receivable, net		197			10,358			—				10,555
Derivative instruments		—			1,618			—				1,618
Prepaid and other current assets		165			864			—				1,029
Investment held in Trust Account		500,550			—			(500,550	)	(d)		—
Total current assets		501,050			13,250			(400,744	)			113,556
Oil and natural gas properties, other property and equipment
Oil and natural gas properties, successful efforts method		—			718,999			(283,919	)	(e)		435,080
Accumulated depreciation, depletion and amortization		—			(241,017	)		241,017		(e)		—
Unproved oil and natural gas properties		—			139,690			998,545		(e)		1,138,235
Other property and equipment, net		—			1,703			—				1,703
Total property and equipment, net		—			619,375			955,643				1,575,018
Noncurrent assets
Derivative instruments		—			245			—				245
Other noncurrent assets		—			1,042			(1,042	)	(f)		—
Total assets	$	501,050		$	633,912		$	553,857			$	1,688,819
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	2		$	23,579		$	—			$	23,581
Derivative instruments		—			1,000			—				1,000
Other current liabilities		300			243			—				543
Total current liabilities		302			24,822			—				25,124
Noncurrent liabilities
Revolving credit facility		—			124,000			(124,000	)	(f)		—
Term loan, net of unamortized deferred financing costs		—			64,762			(64,762	)	(f)		—
Asset retirement obligations		—			2,680			—				2,680
Deferred underwriting compensation		17,500			—			(17,500	)	(g)		—
Deferred tax liability		—			1,954			(1,954	)			—
Derivative instruments		—			557			—				557
Total liabilities		17,802			218,775			(208,216	)			28,361
Class A common stock subject to possible redemption; 47,877,199 shares (at redemption value of approximately $10.00 per share)		478,248			—			(478,248	)	(h)		—
OWNERS' EQUITY/ STOCKHOLDERS' EQUITY
Owners' equity		—			415,137			(415,137	)	(j)		—
Preferred shares, $0.0001 par value; 1,000,000 shares authorized; none issued and outstanding		—			—			—				—
Class A common stock, $0.0001 par value 200,000,000 shares authorized; 2,122,801 shares issued and outstanding at September 30, 2016 (excluding 47,877,199 shares subject to possible redemption)		1			—			1		(k)		17
		—			—			5		(h)		—
		—			—			10		(m)		—
Class B common stock, $0.0001 par value 20,000,000 shares authorized, 12,500,000 shares issued and outstanding at September 30, 2016		1			—			(1	)	(k)		—
Class C common stock, $0.0001 par value; 20,000,000 shares authorized; 20,000,000 shares issued and outstanding at September 30, 2016		—			—			2		(l)		2
Additional paid-in capital		5,460			—			1,004,038		(m)		1,487,741
		—			—			478,243		(h)		—
Retained Earnings (accumulated deficit)		(462	)		—			(11,550	)	(g)		(12,012	)
Total equity		5,000			415,137			1,055,611				1,475,748
Non-controlling interests		—			—			184,710		(i)		184,710
Total Equity		5,000			415,137			1,240,321				1,660,458
Total Liabilities and Equity	$	501,050		$	633,912		$	553,857			$	1,688,819

F-53

1. Basis of Pro Forma Presentation

Overview

        The unaudited pro forma condensed consolidated combined financial statements have been prepared assuming the business combination is accounted for using the acquisition method of accounting with Silver Run as the acquiring entity. Under the acquisition method of accounting, Silver Run's assets and liabilities will retain their carrying values and CRP's assets and liabilities will be recorded at their fair values measured as of the acquisition date. The excess of the purchase price over the estimated fair values of CRP's net assets acquired, if applicable, will be recorded as goodwill. The pro forma adjustments have been prepared as if the business combination and the other related Transactions had taken place on September 30, 2016 in the case of the unaudited pro forma condensed consolidated combined balance sheet and on January 1, 2015 in the case of the unaudited pro forma condensed consolidated combined statements of operations.

        The acquisition method of accounting is based on Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") 805, Business combination ("ASC 805"), and uses the fair value concepts defined in FASB ASC 820, Fair Value Measurements ('ASC 820"). ASC 805 requires, among other things, that most assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date by Silver Run, who was determined to be the accounting acquirer.

        ASC 820 defines the term "fair value," sets forth the valuation requirements for any asset or liability measured at fair value, expands related disclosure requirements and specifies a hierarchy of valuation techniques based on the nature of the inputs used to develop the fair value measures. Fair value is defined in ASC 820 as "the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date." This is an exit price concept for the valuation of the asset or liability. In addition, market participants are assumed to be buyers and sellers in the principal (or the most advantageous) market for the asset or liability. Fair value measurements for an asset assume the highest and best use by these market participants. Many of these fair value measurements can be highly subjective, and it is possible that other professionals, applying reasonable judgment to the same facts and circumstances, could develop and support a range of alternative estimated amounts.

        Under ASC 805, acquisition-related transaction costs are not included as a component of consideration transferred but are accounted for as expenses in the periods in which such costs are incurred, or if related to the issuance of debt, capitalized as debt issuance costs. Acquisition-related transaction costs expected to be incurred as part of the business combination, include estimated fees related to the issuance of long-term debt, as well as advisory, legal and accounting fees.

        The unaudited pro forma condensed consolidated combined financial statements should be read in conjunction with (i) Silver Run's historical financial statements and related notes for the period from November 4, 2015 (date of inception) to December 31, 2015, as well as "Management's Discussion and Analysis of Financial Condition and Results of Operations of Silver Run," which are included in the Proxy Statement, (ii) Silver Run's historical financial statements and related notes for the nine months ended September 30, 2016, as well as "Management's Discussion and Analysis of Financial Condition and Results of Operations," which are included in the Silver Run 10-Q, (iii) CRP's historical consolidated financial statements and related notes for the year ended December 31, 2015, as well as "Management's Discussion and Analysis of Financial Condition and Results of Operations of CRP," which are included in the Proxy Statement, and (iv) CRP's historical consolidated financial statements and related notes for the nine months ended September 30, 2016, as well as "Management's Discussion and Analysis of Financial Condition and Results of Operations" which are included within this registration statement.

F-54

1. Basis of Pro Forma Presentation (Continued)

        The pro forma adjustments represent management's estimates based on information available as of the date of this filing and are subject to change as additional information becomes available and additional analyses are performed. The unaudited pro forma condensed consolidated combined financial statements do not reflect possible adjustments related to restructuring or integration activities that have yet to be determined or transaction or other costs following the business combination that are not expected to have a continuing impact. Further, one-time transaction-related expenses anticipated to be incurred prior to, or concurrent with, closing the business combination and the other related Transactions are not included in the unaudited pro forma condensed consolidated combined statements of operations. However, the impact of such transaction-related expenses is reflected in the unaudited pro forma condensed consolidated combined balance sheet as a decrease to retained earnings and a decrease to cash.

Preliminary Estimated Purchase Price

        The purchase consideration was preliminarily estimated as follows (in thousands):

	At September 30, 2016
Preliminary Purchase Consideration:
Cash	$	1,186,744
Repayment of CRP long-term debt(1)		189,000
Total Purchase Price Consideration		1,375,744
Fair value of non-controlling interest(2)		184,710
Total Purchase Price Consideration and Fair Value of Non-Controlling Interest	$	1,560,454

(1)

Represents the additional contribution that is expected to be made by Silver Run to CRP in exchange for units representing common membership interest in CRP ("CRP Common Units"), to repay CRP's outstanding indebtedness at the Closing (the "Additional Debt Repayment Contribution"). Prior to the consummation of the business combination, Silver Run and CRP intend to amend CRP's credit agreement to permit the business combination and to increase the aggregate commitments thereunder and Silver Run expects to repay all of CRP's outstanding indebtedness at the Closing. Pursuant to the Contribution Agreement, Silver Run will contribute to CRP cash in an amount equal to the net cash proceeds received by Silver Run pursuant to the Transactions, which amount includes the contribution of the cash consideration and the Additional Debt Repayment Contribution, in exchange for a number of CRP Common Units equal to the number of shares of Class A Common Stock outstanding following the completion of the Transactions. As a result, following the completion of the Transactions, Silver Run will own 163.5 million CRP Common Units, representing an approximate 89% interest in CRP.

(2)

Represents the fair value of the non-controlling interest (NCI) attributable to the Centennial Contributors. NCI is the portion of equity (net assets) in a subsidiary not attributable, directly or indirectly to Silver Run. In a business combination the NCI is recognized at its acquisition date fair value in accordance with ASC 805. The fair value of the NCI represents a 10.9% membership interest in CRP.

F-55

1. Basis of Pro Forma Presentation (Continued)

Preliminary Estimated Purchase Price Allocation

        The following table summarizes the allocation of the preliminary estimate of the purchase consideration to the assets acquired and liabilities assumed (in thousands):

	At September 30, 2016
Estimated Fair Value of Assets Acquired
Cash and cash equivalents	$	410
Other current assets		11,222
Derivative instruments		1,863
Oil and Gas Properties(1):
Proved Properties		435,080
Unproved Properties		1,138,235
Other property, plant and equipment		1,703
Goodwill		—
Total Assets Acquired		1,588,513
Estimated Fair Value of Liabilities Assumed
Accounts payable and accrued expenses		23,579
Other current liabilities		243
Revolving credit facility		—
Derivative instruments		1,557
Asset retirement obligation		2,680
Total consideration and fair value	$	1,560,454

(1)

The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates;(iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. The reduction in the carrying cost of the proved properties was impacted by all of these factors, but most notably, the assumptions with respect to future commodity prices as of the valuation date.

2. Pro Forma Adjustments and Assumptions

Pro Forma Adjustments to the Statement of Operations:

a.

Represents the Silver Run historical statement of operations for the nine months ended September 30, 2016 and for the period from November 4, 2015 (date of inception) to December 31, 2015, respectively.

b.

Represents the CRP historical statement of operations for the nine months ended September 30, 2016 and year ended December 31, 2015.

F-56

2. Pro Forma Adjustments and Assumptions (Continued)

c.

Represents the adjustments to depreciation, depletion, and amortization based on the purchase price allocation.

d.

Represents an adjustment to eliminate historical interest income of Silver Run associated with the funds that were previously held in the Trust Account, which will be used to fund a portion of the cash consideration in the business combination.

e.

Represents the following adjustments to interest expense:

(1)

an adjustment to decrease interest expense related to the historical debt of CRP that is to be repaid as part of or just prior to the closing of the business combination (the "Closing").

(2)

an adjustment to increase interest expense by the undrawn commitment fee to be assessed on CRP's revolver in the event that it does not have any amounts drawn on that revolver.

f.

Represents an adjustment to record the tax expense based on total pro forma combined income (loss) before income taxes as if Silver Run had been subject to U.S. federal income tax as a corporation using an estimated effective entity-level income tax rate of 32%, inclusive of all applicable U.S. federal, state and local income taxes.

g.

Represents net income (loss) attributable to the non-controlling interest on total pro forma combined net income (loss).

h.

Pro forma basic earnings per share was computed by dividing pro forma net income attributable to Silver Run by the weighted average shares of Class A Common Stock, as if such shares were issued and outstanding as of January 1, 2015. Pro forma dilutive earnings per share was computed using the "if-converted" method to determine the potential dilutive effect of its Class C Common Stock.

Pro Forma Adjustments to the Balance Sheet:

a.

Represents the Silver Run unaudited historical balance sheet as of September 30, 2016.

b.

Represents the CRP unaudited historical balance sheet as of September 30, 2016.

c.

Represents the net adjustment to cash associated with Silver Run's payment of cash consideration in the business combination:

        Pro forma net adjustment to cash associated with purchase adjustments (in thousands):

	At September 30, 2016
Silver Run cash previously held in Trust Account	$	500,550	(1)
Cash consideration		(1,186,744)	(2)
Proceeds from Private Placements		1,010,050	(3)
Payment of transaction costs		(35,050)	(4)
Payment of CRP's long-term debt		(189,000)	(5)
Net adjustments to cash associated with purchase accounting	$	99,806

(1)

Represents the adjustment related to the reclassification of the cash equivalents held in the Trust Account in the form of investments to cash and cash equivalents to reflect the fact that these investments are available for use in connection with the business combination and the payment of a portion of the cash consideration.

F-57

2. Pro Forma Adjustments and Assumptions (Continued)

(2)

Represents the cash consideration portion of the total consideration that is expected to be paid to effectuate the business combination.

(3)

Represents the issuance of 101,005,000 shares of Class A Common Stock at a price of $10.00 per share in the Private Placements, which will result in aggregate proceeds of $1,010,050,000.

(4)

Reflects the impact of estimated transaction costs of $35.1 million, including

(i)

$17.5 million of deferred underwriting compensation attributable to Silver Run's IPO

(ii)

$6.0 million of estimated fees and expenses attributable to the Private Placements and

(iii)

$11.6 million of banking, legal and accounting fees that are not capitalizable as part of the transaction. In accordance with ASC 805, acquisition-related transaction costs and related charges are not included as a component of consideration to be transferred but are required to be expensed as incurred. The unaudited pro forma condensed consolidated combined balance sheet reflects these costs as a reduction of cash with a corresponding decrease in retained earnings. These costs are not included in the unaudited pro forma condensed consolidated combined statement of operations as they are directly related to the business combination and will be nonrecurring.

(5)

Represents the additional contribution that is expected to be made by Silver Run to CRP, in exchange for CRP Common Units to repay CRP's outstanding indebtedness at the Closing.

d.

Represents the adjustment related to the reclassification of the cash equivalents held in the Trust Account in the form of investments to cash and cash equivalents to reflect the fact that these investments are available for use in connection with the business combination and the payment of a portion of the cash consideration.

e.

The allocation of the estimated fair value of consideration transferred to the estimated fair value of CRP's oil and natural gas properties resulted in the following purchase price allocation adjustments:

(1)

Represents a $714.6 million increase in gross book basis of oil and gas properties to reflect them at fair value. The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. The reduction in the carrying cost of the proved properties was impacted by all of these factors, but most notably, the assumptions with respect to future commodity prices as of the valuation date.

(2)

Represents the elimination of CRP's historical accumulated depletion and amortization ("DD&A") balances.

F-58

2. Pro Forma Adjustments and Assumptions (Continued)

f.

Represents an adjustment related to the repayment of CRP's long-term debt in conjunction with the consummation of the business combination. Prior to the consummation of the business combination, Silver Run and CRP intend to amend CRP's credit agreement to permit the business combination and to increase the aggregate commitments thereunder. In either case, Silver Run expects to repay all of CRP's outstanding indebtedness at the Closing. Debt issuance costs totaling $1.3 million were derecognized as part of the purchase consideration allocation.

g.

Represents the payment of deferred underwriting costs of $17.5 million as well as an adjustment to retained earnings (accumulated deficit) of $11.6 million of banking, legal and accounting fees that are not capitalizable as part of the transaction. The $11.6 million represents an estimate of transaction-related costs provided by our various service providers. The $11.6 million of transaction-related costs are not included in the unaudited pro forma condensed consolidated combined statement of operations as they are directly related to the business combination and will be nonrecurring.

h.

Represents an adjustment to reflect that at the time of issuance, certain of Silver Run's Class A Common Stock was subject to a possible redemption and, as such, an amount of $478.2 million was classified as redeemable equity in Silver Run's historical consolidated balance sheet as of September 30, 2016. Under the assumption that none of the public stockholders elect to have Silver Run redeem these shares in connection with the business combination, the shares are no longer redeemable and have been reclassified from redeemable equity to additional paid in capital and Class A Common Stock, $0.0001 par value.

i.

Represents the fair value of the non-controlling interest (NCI) attributable to the Centennial Contributors. NCI is the portion of equity (net assets) in a subsidiary not attributable, directly or indirectly, to Silver Run. In a business combination, the NCI is recognized at its acquisition-date fair value in accordance with ASC 805.

j.

Represents an adjustment to eliminate CRP historical members' equity in conjunction with the completion of the business combination.

k.

Represents the automatic conversion of Class B Common Stock to Class A Common Stock on a one-for-one basis in accordance with Silver Run's amended and restated certificate of incorporation upon the Closing.

l.

Represents the 20,000,000 shares of Class C Common Stock issued to the Centennial Contributors. Holders of Class C Common Stock will have the right to vote on all matters properly submitted to a vote of the Silver Run stockholders, but will not be entitled to any dividends or any distributions in liquidation from Silver Run. The Centennial Contributors will generally have the right to cause CRP to redeem all or a portion of their CRP Common Units in exchange for shares of Class A Common Stock, or at CRP's option, an equivalent amount of cash. Upon 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.

m.

Reflects an adjustment for the additional paid in capital associated with the issuance of 101,005,000 shares of Class A Common Stock at a price of $10.00 per share in the Private Placements, which will result in an aggregate of $1,004,038,000, net of estimated fees and expenses, which is reflected as an adjustment to additional paid in capital. Also includes an adjustment of $10,000 for the par value of the Class A Common Stock associated with the issuance of new shares attributable to the Private Placements.

F-59

Annex A

SUBSCRIPTION AGREEMENT

        This SUBSCRIPTION AGREEMENT is entered into this 27th day of November, 2016 (this "Subscription Agreement"), by and between Centennial Resource Development, Inc., a Delaware corporation (the "Company"), and Riverstone Silverback Holdings, L.P. ("Subscriber").

        WHEREAS, SB RS Holdings, LLC, a Delaware limited liability company ("SB RS Holdings"), has entered into that certain Purchase and Sale Agreement, dated as of November 21, 2016 (the "Purchase Agreement"), pursuant to which SB RS Holdings will acquire certain assets (the "Transferred Property") from Silverback Exploration, LLC and Silverback Operating, LLC, each a Delaware limited liability company (collectively "Silverback"), on the terms and subject to the conditions set forth therein;

        WHEREAS, pursuant to Section 11.5 of the Purchase Agreement, SB RS Holdings has the right to assign (the "Assignment") all of its rights and obligations under the Purchase Agreement to Centennial Resource Production, LLC, a controlled subsidiary of the Company (the "Purchaser"), and the Purchaser, upon such Assignment, would acquire the Transferred Property instead of SB RS Holdings, on the terms and subject to the conditions set forth therein (the "Transaction");

        WHEREAS, SB RS Holdings, Riverstone Capital Services LLC, the Company and the Purchaser have entered into that certain Agreement to Assign, dated as of November 27, 2016 (the "Agreement to Assign"), pursuant to which SB RS Holdings has agreed to make the Assignment, and the Purchaser has agreed to accept the Assignment, on the terms and subject to the conditions set forth therein;

        WHEREAS, to finance a portion of the Transaction, Subscriber desires to subscribe for and purchase from the Company (a) an aggregate of approximately $400 million in (i) shares (the "Class A Acquired Shares") of the Company's Class A common stock, par value $0.0001 per share (the "Class A Common Stock"), at a purchase price of $14.54 per share, subject to adjustment under Section 1(c) below, and (ii) shares (the "Series B Acquired Shares") of the Company's convertible Series B Preferred Stock, par value $0.0001 per share (the "Series B Preferred Stock"), at a purchase price of $ 3,635.00 per share (or $14.54 per share on an as-converted basis), subject to adjustment under Section 1(c) below, and (b) at Subscriber's election after consultation with the Company, up to an additional approximately $100 million in additional shares of Class A Common Stock and/or Series B Preferred Stock, as mutually agreed by Subscriber and the Company, at the respective purchase prices set forth in clause (a) above (the "Additional Acquired Shares" and, together with the Class A Acquired Shares and the Series B Acquired Shares, the "Acquired Shares"; and as used herein, unless the context otherwise requires, Class A Acquired Shares, Series B Acquired Shares and Acquired Shares shall be deemed to refer to and include the Conversion Shares (as defined below)), or, with respect to all such Acquired Shares, the aggregate amount set forth on Subscriber's signature page hereto (the "Purchase Price"), such allocation between Class A Acquired Shares and Class B Acquired Shares and the final number of Additional Acquired Shares to be determined in accordance with Section 1 below, and the Company desires to issue and sell to Subscriber the Acquired Shares in consideration of the payment of the Purchase Price by or on behalf of Subscriber to the Company on or prior to the Closing Date (as defined below);

        WHEREAS, the Series B Preferred Stock will have the terms set forth on Annex B hereto, including the automatic conversion of the Series B Preferred Stock into shares of Class A Common Stock on a 250-for-one basis, subject to adjustment as provided therein, upon approval by the stockholders of the Company of the issuance of such shares of Class A Common Stock, as required by the rules of The NASDAQ Capital Market ("NASDAQ"); and

        WHEREAS, the Company may, but is not obligated to, finance any of the remaining portion of the purchase price for the Transaction (the "Remaining Purchase Price") by issuing additional shares of

A-1

its common stock or preferred stock pursuant to subscription agreements substantially similar to this Subscription Agreement (any such agreements, the "Other Subscription Agreements").

        NOW, THEREFORE, in consideration of the foregoing and the mutual representations, warranties and covenants, and subject to the conditions, herein contained, and intending to be legally bound hereby, the parties hereto hereby agree as follows:

        1.    Subscription.    

        a.     Subject to the terms and conditions hereof, Subscriber hereby agrees to subscribe for and purchase, and the Company hereby agrees to issue and sell to Subscriber, upon the payment of the Purchase Price, the Acquired Shares (such subscription and issuance, the "Subscription").

        b.     On or prior to the date on which any Other Subscription Agreement, if any, is entered into, after consultation with the Company, Subscriber shall notify the Company of the number of Additional Acquired Shares constituting "Acquired Shares" hereunder that Subscriber shall elect and be obligated to purchase on the Closing Date as provided herein, which notice shall include the allocation of Class A Acquired Shares and Series B Acquired Shares constituting the "Acquired Shares" (including the Additional Acquired Shares) to be purchased hereunder (the "Total Acquired Shares"); provided that the maximum number of Class A Acquired Shares to be purchased hereunder (the "Maximum Share Number"), together with any additional shares of Class A Common Stock to be issued by the Company pursuant to all Other Subscription Agreements, if any, in the aggregate, does not exceed 19.9% of the Company's outstanding shares of Class A Common Stock and Class C Common Stock (as defined below), on a combined basis, on the date hereof, and, to the extent the Maximum Share Number would be exceeded by issuing all Acquired Shares as shares of Class A Common Stock, Subscriber shall instead be obligated to purchase, and the Company shall be obligated to issue to Subscriber, that number of Series B Acquired Shares that, together with the number of Class A Acquired Shares to be purchased hereunder, equals the number of Total Acquired Shares to be purchased hereunder. At such time, Subscriber and the Company shall update and amend Subscriber's signature page hereto to reflect the number of Acquired Shares to be purchased, and the aggregate Purchase Price to be paid, on the Closing Date as provided herein.

        c.     Notwithstanding anything to the contrary set forth herein, if the Company determines to finance any portion of the Remaining Purchase Price by issuing additional shares of its common stock or preferred stock to one or more additional purchasers (the "Other Purchasers") pursuant to any Other Subscription Agreement or otherwise at a price per share less than the Purchase Price payable by Subscriber hereunder, then Subscriber's Purchase Price shall be reduced to equal the lowest per share purchase price to be paid by any such Other Purchaser (including on an as-converted basis for any shares of Series B Preferred Stock).

        2.    Closing.    

        a.     The closing of the Subscription contemplated hereby (the "Closing") is contingent upon the substantially concurrent consummation of the Transaction and shall occur immediately prior thereto. The Closing and the closing of the Transaction shall occur on December 30, 2016, subject to extension upon five (5) business days' prior written notice to Subscriber (such date, including as so extended, the "Closing Date"). At least three (3) business days prior to the Closing Date, Subscriber shall deliver to the Company, to be held in escrow until the Closing, the Purchase Price for the Acquired Shares by wire transfer of U.S. dollars in immediately available funds to the account specified by the Company in Annex B hereto. Immediately prior to the closing of the Transaction on the Closing Date, (a) the Purchase Price shall be released from escrow automatically and without further action by the Company or Subscriber, and (b) upon such release, the Company shall deliver to Subscriber (i) the Acquired Shares in book entry form, free and clear

A-2

of any liens or other restrictions whatsoever (other than those arising under state or federal securities laws), in the name of Subscriber (or its nominee in accordance with its delivery instructions) or to a custodian designated by Subscriber, as applicable, and (ii) written notice from the Company or its transfer agent evidencing the issuance to Subscriber of the Acquired Shares on and as of the Closing Date. In the event the Closing does not occur on the Closing Date, the Company shall promptly (but not later than one (1) business day thereafter) return the Purchase Price to Subscriber.

        b.     The Closing shall be subject to the conditions that, on the Closing Date:

          (i)  no suspension of the qualification of the Acquired Shares for offering or sale or trading in any jurisdiction, or initiation or threatening of any proceedings for any of such purposes, shall have occurred;

         (ii)  all representations and warranties of the Company and Subscriber contained in this Subscription Agreement shall be true and correct in all material respects (other than representations and warranties that are qualified as to materiality or Material Adverse Effect (as defined herein), which representations and warranties shall be true in all respects) at and as of the Closing Date, and consummation of the Closing shall constitute a reaffirmation by each of the Company and Subscriber of each of the representations, warranties and agreements of each such party contained in this Subscription Agreement as of the Closing Date, but in each case without giving effect to consummation of the Transaction;

        (iii)  the Company shall have performed, satisfied and complied in all material respects with all covenants, agreements and conditions required by this Subscription Agreement to be performed, satisfied or complied with by it at or prior to the Closing;

        (iv)  the Company shall have obtained approval of the NASDAQ to list the Acquired Shares (other than the Series B Acquired Shares), subject to official notice of issuance;

         (v)  the Company shall have filed the Certificate of Designation relating to the Series B Preferred Stock with the State of Delaware;

        (vi)  no governmental authority shall have enacted, issued, promulgated, enforced or entered any judgment, order, law, rule or regulation (whether temporary, preliminary or permanent) which is then in effect and has the effect of making consummation of the transactions contemplated hereby illegal or otherwise restraining or prohibiting consummation of the transactions contemplated hereby, and no governmental authority shall have instituted or threatened in writing a proceeding seeking to impose any such restraint or prohibition;

       (vii)  the Company shall have received proceeds from debt or equity financings on terms satisfactory to the Company that, together with the proceeds from the sale of the Acquired Shares hereunder, will be sufficient for the Company to pay the purchase price for the Transaction pursuant to the Purchase Agreement and the Assignment on the Closing Date;

      (viii)  the Transaction shall be consummated substantially concurrently with the Closing in accordance with the terms of the Purchase Agreement.

        c.     At the Closing, the parties hereto shall execute and deliver such additional documents and take such additional actions as the parties reasonably may deem to be practical and necessary in order to consummate the Subscription as contemplated by this Subscription Agreement.

        3.    Company Representations and Warranties.    The Company represents and warrants that:

        a.     Each of the Company and its subsidiaries, including the Purchaser, has been duly incorporated and is validly existing as a corporation or limited liability company in good standing under the laws of the State of Delaware, with corporate or limited liability company power and

A-3

authority, as applicable, to (i) own, lease and operate its properties and conduct its business as presently conducted and (ii) with respect to the Company, to enter into, deliver and perform its obligations under this Subscription Agreement. The Company and each of its subsidiaries is duly qualified and in good standing to do business in each jurisdiction in which the business it is conducting, or the operation, ownership or leasing of its properties, makes such qualification necessary, other than where the failure to be duly incorporated, validly existing, or to so qualify or be in good standing has not had and would not be reasonably likely to have, individually or in the aggregate, a Material Adverse Effect.

        b.     The Acquired Shares have been duly authorized and, when issued and delivered to Subscriber against full payment therefor in accordance with the terms of this Subscription Agreement, the Acquired Shares will be validly issued, fully paid and non-assessable and will not have been issued in violation of or subject to any preemptive or similar rights created under the Company's second amended and restated certificate of incorporation, under the Delaware General Corporation Law.

        c.     The shares of Class A Common Stock issuable upon conversion of the Series B Preferred Stock (the "Conversion Shares") have been duly authorized and, when issued and delivered to Subscriber against full payment therefor in accordance with the terms thereof, will be validly issued, fully paid and non-assessable and will not have been issued in violation of or subject to any preemptive or similar rights created under the Company's second amended and restated certificate of incorporation, under the Delaware General Corporation Law.

        d.     The Conversion Shares have been reserved for issuance upon conversion of the Series B Preferred Stock in accordance with the terms thereof.

        e.     There are no securities or instruments issued by or to which the Company is a party containing anti-dilution or similar provisions that will be triggered by the issuance of (i) the Acquired Shares, or (ii) the shares to be issued pursuant to any Other Subscription Agreement.

        f.      This Subscription Agreement has been duly authorized, executed and delivered by the Company and is enforceable against it in accordance with its terms, except as may be limited or otherwise affected by (i) bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or other laws relating to or affecting the rights of creditors generally, and (ii) principles of equity, whether considered at law or equity.

        g.     The execution and delivery of this Subscription Agreement, the issuance and sale of the Acquired Shares and the compliance by the Company with all of the provisions of this Subscription Agreement and the consummation of the transactions contemplated herein will not conflict with or result in a breach or violation of any of the terms or provisions of, or constitute a default under, or result in the creation or imposition of any lien, charge or encumbrance upon any of the property or assets of the Company pursuant to the terms of (i) any indenture, mortgage, deed of trust, loan agreement, lease, license or other agreement or instrument to which the Company or any of its subsidiaries is a party or by which the Company or any of its subsidiaries is bound or to which any of the property or assets of the Company or any of its subsidiaries is subject, which would reasonably be expected to have a material adverse effect on the business, properties, financial condition, stockholders' equity or results of operations of the Company and its subsidiaries, taken as a whole (a "Material Adverse Effect"), or materially affect the validity of the Acquired Shares or the legal authority of the Company to comply in all material respects with the terms of this Subscription Agreement; (ii) the organizational documents of the Company or any of its subsidiaries; or (iii) any statute or any judgment, order, rule or regulation of any court or governmental agency or body, domestic or foreign, having jurisdiction over the Company, any of its subsidiaries or any of their respective properties that, in the case of clauses (i) and (iii), would reasonably be expected to have a Material Adverse Effect or affect the validity of the Acquired

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Shares or the legal authority of the Company to comply in all material respects with this Subscription Agreement.

        h.     The Company is not in default or violation (and no event has occurred which, with notice or the lapse of time or both, would constitute a default or violation) of any term, condition or provision of (i) the organizational documents of the Company or any of its subsidiaries, (ii) any loan or credit agreement, note, bond, mortgage, indenture, lease or other agreement, permit, franchise or license to which the Company or any of its subsidiaries is now a party or by which the Company's or any of its subsidiaries' properties or assets are bound or (iii) any statute or any judgment, order, rule or regulation of any court or governmental agency or body, domestic or foreign, having jurisdiction over the Company, any of its subsidiaries or any of their respective properties, except, in the case of clauses (ii) and (iii), for defaults or violations that have not had and would not be reasonably likely to have, individually or in the aggregate, a Material Adverse Effect.

        i.      The Company is not required to obtain any consent, waiver, authorization or order of, give any notice to, or make any filing or registration with, any court or other federal, state, local or other governmental authority, self-regulatory organization (including Nasdaq) or other person in connection with the execution, delivery and performance by the Company of this Subscription Agreement (including, without limitation, the issuance of the Acquired Shares), other than (i) the filing with the Securities and Exchange Commission (the "Commission") of the Registration Statement (as defined below), (ii) filings required by applicable state securities laws, (iii) if applicable, the filing of a Notice of Exempt Offering of Securities on Form D with the Commission under Regulation D of the Securities Act, (iv) the filings required in accordance with Section 8(m) of this Subscription Agreement; (v) those required by NASDAQ, including with respect to obtaining the Stockholder Approval (as defined below), and (vi) the failure of which to obtain would not be reasonably likely to have, individually or in the aggregate, a Material Adverse Effect.

        j.      The authorized capital stock of the Company consists of 620,000,000 shares of common stock of the Company, par value $0.0001 per share ("Common Stock"), including (x) 600,000,000 shares of Class A Common Stock and (y) 20,000,000 shares of Class C Common Stock ("Class C Common Stock"), and 1,000,000 shares of preferred stock of the Company, par value $0.0001 per share ("Preferred Stock"). As of November 15, 2016: (i) 164,349,079 shares of Class A Common Stock, 19,155,921 shares of Class C Common Stock and one share of Preferred Stock, designated as the "Series A Preferred Stock," were issued and outstanding; (ii) 24,666,643 warrants, each entitling the holder thereof to purchase one share of Class A Common Stock at an exercise price of $11.50 per share of Class A Common Stock ("Warrants") were issued and outstanding; (iii) 16,500,000 shares of Class A Common Stock were available for issuance under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan, of which options to purchase 1,550,000 shares of Class A Common Stock were outstanding; and (iv) no indebtedness of the Company having the right to vote (or convertible into equity having the right to vote) on any matters on which the equityholders of the Company may vote was issued and outstanding. All (i) issued and outstanding shares of Common Stock and Preferred Stock have been duly authorized and validly issued, are fully paid and are non-assessable and are not subject to preemptive rights and (ii) outstanding Warrants have been duly authorized and validly issued, are fully paid and are not subject to preemptive rights. Except as set forth above and pursuant to the Other Subscription Agreements, there are no outstanding options, warrants or other rights to subscribe for, purchase or acquire from the Company any Common Stock or other equity interests in the Company (collectively, "Equity Interests") or securities convertible into or exchangeable or exercisable for Equity Interests.

        k.     The Company has made available to Subscriber (including via the Commission's EDGAR system) a copy of each form, report, statement, schedule, prospectus, proxy, registration statement

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and other document filed by the Company with the Commission since its initial registration of the Class A Common Stock (the "SEC Documents"). None of the SEC Documents filed under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), contained, when filed or, if amended, as of the date of such amendment with respect to those disclosures that are amended, any untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein, in light of the circumstances under which they were made, not misleading; provided, that the Company makes no such representation or warranty with respect to any information relating to Silverback or any of its affiliates included in any SEC Document or filed as an exhibit thereto. The Company has timely filed each report, statement, schedule, prospectus, and registration statement that the Company was required to file with the Commission since its inception. There are no material outstanding or unresolved comments in comment letters from the Commission Staff with respect to any of the SEC Documents.

        l.      The financial statements of the Company included in the SEC Documents complied as to form in all material respects with Regulation S-X of the Commission, were prepared in accordance with U.S. generally accepted accounting principles ("GAAP") applied on a consistent basis during the periods involved (except as may be indicated in the notes thereto or, in the case of the unaudited statements, as permitted by Rule 10-01 of Regulation S-X of the Commission) and fairly present in all material respects in accordance with applicable requirements of GAAP (subject, in the case of the unaudited statements, to normal year-end audit adjustments) the financial position of the Company as of their respective dates and the results of operations and the cash flows of the Company for the periods presented therein.

        m.    The Company has not received any written communication since December 31, 2015 from a governmental entity that alleges that the Company or any of its subsidiaries is not in compliance with or is in default or violation of any applicable law, except where such non-compliance, default or violation would not, individually or in the aggregate, be reasonably likely to have a Material Adverse Effect.

        n.     Except for such matters as have not had and would not be reasonably likely to have, individually or in the aggregate, a Material Adverse Effect, there is no (i) proceeding pending, or, to the knowledge of the Company, threatened against the Company or any of its subsidiaries or (ii) judgment, decree, injunction, ruling or order of any governmental entity or arbitrator outstanding against the Company or any of its subsidiaries.

        o.     The lists of exhibits contained in the SEC Documents set forth a true and complete list, as of the date of this Subscription Agreement, of each agreement to which the Company or any of its subsidiaries is a party (other than the Agreement to Assign, this Subscription Agreement and the Other Subscription Agreements) that is of a type that would be required to be included as an exhibit to a Registration Statement on Form S-1 pursuant to Items 601(b)(2), (4), (9) or (10) of Regulation S-K of the Commission if such a registration statement were filed by the Company on the date of this Subscription Agreement.

        p.     The issued and outstanding shares of Class A Common Stock are registered pursuant to Section 12(b) of the Exchange Act and are listed for trading on the NASDAQ under the symbol "CDEV". There is no suit, action, proceeding or investigation pending or, to the knowledge of the Company, threatened against the Company by NASDAQ or the Commission with respect to any intention by such entity to deregister the Class A Common Stock or prohibit or terminate the listing of the Class A Common Stock on NASDAQ. The Company has taken no action that is designed to terminate the registration of the Class A Common Stock under the Exchange Act.

        q.     All material Tax Returns (as defined in the Purchase Agreement) required to be filed by or with respect to the Company and its subsidiaries have been duly and timely filed (taking into account extension of time for filing) with the appropriate governmental entity, and all such Tax

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Returns were true, correct and complete in all material respects. The Company and its subsidiaries have paid all Taxes (as defined in the Purchase Agreement) and other assessments due, whether or not disputed. The Company and its subsidiaries do not have any liabilities for Taxes of any other person or entity by contract, as a transferee or successor, under U.S. Treasury Regulation Section 1.1502-6 or analogous state, county, local or foreign provision or otherwise.

        r.     The Company is not, and immediately after receipt of payment for the Acquired Shares will not be, an "investment company" within the meaning of the Investment Company Act of 1940, as amended.

        s.     Assuming the accuracy of Subscriber's representations and warranties set forth in Section 4 of this Subscription Agreement, no registration under the Securities Act is required for the offer and sale of the Acquired Shares by the Company to Subscriber.

        t.      Neither the Company nor any person acting on its behalf has engaged or will engage in any form of general solicitation or general advertising (within the meaning of Regulation D) in connection with any offer or sale of the Acquired Shares.

        u.     In the event that any Other Subscription Agreement, if any, expressly contains additional representations and warranties of the Company, this Subscription Agreement shall be deemed to include, and shall incorporate by reference, such additional representations and warranties set forth in such Other Subscription Agreement, as if the same were expressly set forth herein.

        4.    Subscriber Representations and Warranties.    Subscriber represents and warrants that:

        a.     Subscriber has been duly formed or incorporated and is validly existing in good standing under the laws of its jurisdiction of incorporation or formation, with power and authority to enter into, deliver and perform its obligations under this Subscription Agreement.

        b.     This Subscription Agreement has been duly authorized, executed and delivered by Subscriber. This Subscription Agreement is enforceable against Subscriber in accordance with its terms, except as may be limited or otherwise affected by (i) bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or other laws relating to or affecting the rights of creditors generally, and (ii) principles of equity, whether considered at law or equity.

        c.     The execution, delivery and performance by Subscriber of this Subscription Agreement and the consummation of the transactions contemplated herein will not conflict with or result in a breach or violation of any of the terms or provisions of, or constitute a default under, or result in the creation or imposition of any lien, charge or encumbrance upon any of the property or assets of Subscriber pursuant to the terms of (i) any indenture, mortgage, deed of trust, loan agreement, lease, license or other agreement or instrument to which Subscriber is a party or by which Subscriber is bound or to which any of the property or assets of Subscriber is subject, which would reasonably be expected to have a material adverse effect on the business, properties, financial condition, stockholders' equity or results of operations of Subscriber (a "Subscriber Material Adverse Effect") or materially affect the legal authority of Subscriber to comply in all material respects with the terms of this Subscription Agreement; (ii) the organizational documents of Subscriber; or (iii) any statute or any judgment, order, rule or regulation of any court or governmental agency or body, domestic or foreign, having jurisdiction over Subscriber or any of its properties that, in the case of clauses (i) and (iii), would reasonably be expected to have a Subscriber Material Adverse Effect or affect the legal authority of Subscriber to comply in all material respects with this Subscription Agreement.

        d.     Subscriber (i) is a "qualified institutional buyer" (as defined in Rule 144A under the Securities Act) or an institutional "accredited investor" (within the meaning of Rule 501(a) under the Securities Act) satisfying the applicable requirements set forth on Schedule A, (ii) is acquiring

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the Acquired Shares only for its own account and not for the account of others, or if Subscriber is subscribing for the Acquired Shares as a fiduciary or agent for one or more investor accounts, each owner of such account is a qualified institutional buyer and Subscriber has full investment discretion with respect to each such account, and the full power and authority to make the acknowledgements, representations and agreements herein on behalf of each owner of each such account, and (iii) is not acquiring the Acquired Shares with a view to, or for offer or sale in connection with, any distribution thereof in violation of the Securities Act (and shall provide the requested information on Schedule A following the signature page hereto). Subscriber is not an entity formed for the specific purpose of acquiring the Acquired Shares.

        e.     Subscriber understands that the Acquired Shares are being offered in a transaction not involving any public offering within the meaning of the Securities Act and that the Acquired Shares have not been registered under the Securities Act. Subscriber understands that the Acquired Shares may not be resold, transferred, pledged or otherwise disposed of by Subscriber absent an effective registration statement under the Securities Act, except (i) to the Company or a subsidiary thereof, (ii) to non-U.S. persons pursuant to offers and sales that occur outside the United States within the meaning of Regulation S under the Securities Act or (iii) pursuant to another applicable exemption from the registration requirements of the Securities Act, and, in each of cases (i) and (iii), in accordance with any applicable securities laws of the states and other jurisdictions of the United States, and that any certificates representing the Acquired Shares shall contain a legend to such effect. Subscriber acknowledges that the Acquired Shares will not be eligible for resale pursuant to Rule 144A promulgated under the Securities Act. Subscriber understands and agrees that the Acquired Shares will be subject to transfer restrictions and, as a result of these transfer restrictions, Subscriber may not be able to readily resell the Acquired Shares and may be required to bear the financial risk of an investment in the Acquired Shares for an indefinite period of time. Subscriber understands that it has been advised to consult legal counsel prior to making any offer, resale, pledge or transfer of any of the Acquired Shares.

        f.      Subscriber understands and agrees that Subscriber is purchasing the Acquired Shares directly from the Company. Subscriber further acknowledges that there have been no representations, warranties, covenants and agreements made to Subscriber by the Company, Silverback or any of their respective officers or directors, expressly or by implication, other than those representations, warranties, covenants and agreements of the Company included in this Subscription Agreement.

        g.     Subscriber represents and warrants that its acquisition and holding of the Acquired Shares will not constitute or result in a non-exempt prohibited transaction under Section 406 of the Employee Retirement Income Security Act of 1974, as amended, Section 4975 of the Internal Revenue Code of 1986, as amended, or any applicable similar law.

        h.     In making its decision to purchase the Acquired Shares, Subscriber represents that it has relied solely upon independent investigation made by Subscriber. Subscriber acknowledges and agrees that Subscriber has received such information as Subscriber deems necessary in order to make an investment decision with respect to the Acquired Shares, including with respect to the Company, Silverback and the Transaction. Subscriber represents and agrees that Subscriber and Subscriber's professional advisor(s), if any, have had the full opportunity to ask such questions, receive such answers and obtain such information as Subscriber and such undersigned's professional advisor(s), if any, have deemed necessary to make an investment decision with respect to the Acquired Shares.

        i.      Subscriber became aware of this offering of the Acquired Shares solely by means of direct contact between Subscriber and the Company or by means of contact from Citigroup Global Markets Inc. ("Citi"), acting as placement agent for the Company, and the Acquired Shares were

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offered to Subscriber solely by direct contact between Subscriber and the Company or by contact between Subscriber and Citi. Subscriber did not become aware of this offering of the Acquired Shares, nor were the Acquired Shares offered to Subscriber, by any other means. Subscriber acknowledges that the Company represents and warrants that the Acquired Shares (i) were not offered by any form of general solicitation or general advertising and (ii) are not being offered in a manner involving a public offering under, or in a distribution in violation of, the Securities Act, or any state securities laws.

        j.      Subscriber acknowledges that it is aware that there are substantial risks incident to the purchase and ownership of the Acquired Shares. Subscriber has such knowledge and experience in financial and business matters as to be capable of evaluating the merits and risks of an investment in the Acquired Shares, and Subscriber has sought such accounting, legal and tax advice as Subscriber has considered necessary to make an informed investment decision.

        k.     Subscriber represents and acknowledges that Subscriber has adequately analyzed and fully considered the risks of an investment in the Acquired Shares and determined that the Acquired Shares are a suitable investment for Subscriber and that Subscriber is able at this time and in the foreseeable future to bear the economic risk of a total loss of Subscriber's investment in the Company. Subscriber acknowledges specifically that a possibility of total loss exists.

        l.      Subscriber understands and agrees that no federal or state agency has passed upon or endorsed the merits of the offering of the Acquired Shares or made any findings or determination as to the fairness of this investment.

        m.    Subscriber represents and warrants that Subscriber is not (i) a person or entity named on the List of Specially Designated Nationals and Blocked Persons administered by the U.S. Treasury Department's Office of Foreign Assets Control ("OFAC") or in any Executive Order issued by the President of the United States and administered by OFAC ("OFAC List"), or a person or entity prohibited by any OFAC sanctions program, (ii) a Designated National as defined in the Cuban Assets Control Regulations, 31 C.F.R. Part 515, or (iii) a non-U.S. shell bank or providing banking services indirectly to a non-U.S. shell bank (collectively, a "Prohibited Investor"). Subscriber agrees to provide law enforcement agencies, if requested thereby, such records as required by applicable law, provided that Subscriber is permitted to do so under applicable law. Subscriber represents that if it is a financial institution subject to the Bank Secrecy Act (31 U.S.C. Section 5311 et seq.) (the "BSA"), as amended by the USA PATRIOT Act of 2001 (the "PATRIOT Act"), and its implementing regulations (collectively, the "BSA/PATRIOT Act"), that Subscriber maintains policies and procedures reasonably designed to comply with applicable obligations under the BSA/PATRIOT Act. Subscriber also represents that, to the extent required, it maintains policies and procedures reasonably designed for the screening of its investors against the OFAC sanctions programs, including the OFAC List. Subscriber further represents and warrants that, to the extent required, it maintains policies and procedures reasonably designed to ensure that the funds held by Subscriber and used to purchase the Acquired Shares were legally derived.

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        5.    Registration Rights; Transfer.    

        a.     The Company agrees that, within seventy-five (75) calendar days after the Closing, the Company will file with the Commission (at the Company's sole cost and expense) a registration statement registering the resale of the Class A Acquired Shares (the "Registration Statement"), and the Company shall use its commercially reasonable efforts to have the Registration Statement declared effective as soon as practicable after the filing thereof, but no later than the earlier of (i) the 90th calendar day following the filing thereof and (ii) the 10th business day after the date the Company is notified (orally or in writing, whichever is earlier) by the Commission that the Registration Statement will not be "reviewed" or will not be subject to further review (such earlier date, the "Effectiveness Deadline"); provided, however, that the Company's obligations to include the Class A Acquired Shares in the Registration Statement are contingent upon Subscriber furnishing in writing to the Company such information regarding Subscriber, the securities of the Company held by Subscriber and the intended method of disposition of the Class A Acquired Shares as shall be reasonably requested by the Company to effect the registration of the Class A Acquired Shares, and shall execute such documents in connection with such registration as the Company may reasonably request that are customary of a selling stockholder in similar situations.

        b.     The Company shall, notwithstanding any termination of this Subscription Agreement, indemnify, defend and hold harmless Subscriber (to the extent a seller under the Registration Statement), the officers, directors, agents, partners, members, managers, stockholders, affiliates, employees and investment advisers of each of them, each person who controls Subscriber (within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act) and the officers, directors, partners, members, managers, stockholders, agents, affiliates, employees and investment advisers of each such controlling person, to the fullest extent permitted by applicable law, from and against any and all losses, claims, damages, liabilities, costs (including, without limitation, reasonable costs of preparation and investigation and reasonable attorneys' fees) and expenses (collectively, "Losses"), as incurred, that arise out of or are based upon (i) any untrue or alleged untrue statement of a material fact contained in the Registration Statement, any prospectus included in the Registration Statement or any form of prospectus or in any amendment or supplement thereto or in any preliminary prospectus, or arising out of or relating to any omission or alleged omission to state a material fact required to be stated therein or necessary to make the statements therein (in the case of any prospectus or form of prospectus or supplement thereto, in light of the circumstances under which they were made) not misleading, or (ii) any violation or alleged violation by the Company of the Securities Act, Exchange Act or any state securities law or any rule or regulation thereunder, in connection with the performance of its obligations under this Section 5, except to the extent, but only to the extent, that such untrue statements, alleged untrue statements, omissions or alleged omissions are based solely upon information regarding Subscriber furnished in writing to the Company by Subscriber expressly for use therein. The Company shall notify Subscriber promptly of the institution, threat or assertion of any proceeding arising from or in connection with the transactions contemplated by this Section 5 of which the Company is aware. Such indemnity shall remain in full force and effect regardless of any investigation made by or on behalf of an indemnified party and shall survive the transfer of the Class A Acquired Shares by Subscriber.

        c.     Subscriber shall, severally and not jointly with any other subscriber, indemnify and hold harmless the Company, its directors, officers, agents and employees, each person who controls the Company (within the meaning of Section 15 of the Securities Act and Section 20 of the Exchange Act), and the directors, officers, agents or employees of such controlling persons, to the fullest extent permitted by applicable law, from and against all Losses, as incurred, arising out of or are based upon any untrue or alleged untrue statement of a material fact contained in any Registration Statement, any prospectus included in the Registration Statement, or any form of prospectus, or in

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any amendment or supplement thereto or in any preliminary prospectus, or arising out of or relating to any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein (in the case of any prospectus, or any form of prospectus or supplement thereto, in light of the circumstances under which they were made) not misleading to the extent, but only to the extent, that such untrue statements or omissions are based solely upon information regarding Subscriber furnished in writing to the Company by Subscriber expressly for use therein. In no event shall the liability of Subscriber be greater in amount than the dollar amount of the net proceeds received by Subscriber upon the sale of the Class A Acquired Shares giving rise to such indemnification obligation.

        d.     Prior to the Special Meeting, Subscriber shall not sell, contract to sell, pledge or otherwise dispose of any Series B Acquired Shares without the prior written consent of the Company, other than to affiliates of Subscriber.

        6.    Additional Agreements.    The Company shall use its commercially reasonable efforts to (a) file, within seventy-five (75) calendar days following the Closing Date, a proxy statement for a special meeting of its stockholders (the "Special Meeting") to be held to seek the approval, as required by the NASDAQ, of the issuance of the shares of Class A Common Stock issuable upon conversion of the Series B Preferred Stock (the "Stockholder Approval"), (b) mail a definitive proxy statement for such special meeting within ten (10) business days of the later of (i) the SEC notifying the Company that it will not review or has no further comment on such proxy statement and (ii) the SEC notifying the Company that it will not review or has no further comment on the Registration Statement, and (c) hold such special meeting within thirty (30) days of the mailing such definitive proxy statement.

        7.    Termination.    This Subscription Agreement shall terminate and be void and of no further force and effect, and all rights and obligations of the parties hereunder shall terminate without any further liability on the part of any party in respect thereof, upon the earlier to occur of (a) such date and time as the Purchase Agreement is terminated in accordance with its terms, (b) the consummation of the transactions contemplated by the Purchase Agreement pursuant to the terms thereof by SB RS Holdings without the Assignment to the Purchaser pursuant to the terms of the Agreement to Assign, (c) upon the mutual written agreement of each of the parties hereto to terminate this Subscription Agreement, (d) if any of the conditions to Closing set forth in Section 2 of this Subscription Agreement are not satisfied on or prior to the Closing and, as a result thereof, the transactions contemplated by this Subscription Agreement are not consummated at the Closing or (e) January 31, 2017, if the Closing has not occurred by such date (subject to extension to a date no later than February 15, 2017 if the Purchase Agreement "Outside Date" (as defined therein) is correspondingly extended and the Company provides Subscriber notice of such extension or anticipated extension at least two (2) business days prior to January 31, 2017); provided, that nothing herein will relieve any party from liability for any willful breach hereof prior to the time of termination, and each party will be entitled to any remedies at law or in equity to recover losses, liabilities or damages arising from such breach. The Company shall notify Subscriber of the termination of the Purchase Agreement promptly after the termination of such agreement or the consummation of the transactions by SB RS Holdings without the Assignment to the Purchaser promptly after such consummation.

        8.    Miscellaneous.

        a.     Subscriber acknowledges that the Company and others will rely on the acknowledgments, understandings, agreements, representations and warranties contained in this Subscription Agreement. Prior to the Closing, Subscriber agrees to promptly notify the Company if any of the acknowledgments, understandings, agreements, representations and warranties of Subscriber set forth herein are no longer accurate in all material respects. The Company acknowledges that Subscriber and others will rely on the acknowledgments, understandings, agreements, representations and warranties contained in this Subscription Agreement. Prior to the Closing, the

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Company agrees to promptly notify Subscriber if any of the acknowledgments, understandings, agreements, representations and warranties of the Company set forth herein are no longer accurate in all material respects.

        b.     Each of the Company and Subscriber is entitled to rely upon this Subscription Agreement and is irrevocably authorized to produce this Subscription Agreement or a copy hereof to any interested party in any administrative or legal proceeding or official inquiry with respect to the matters covered hereby.

        c.     This Subscription Agreement and all of Subscriber's rights and obligations hereunder (including Subscriber's obligation to purchase the Acquired Shares) may be transferred or assigned, at any time and from time to time, to one or more parties, in related or unrelated transactions (each such transferee, a "Transferee"). Upon any such assignment:

          (i)  the applicable Transferee shall enter into a subscription agreement (each such subscription agreement, a "New Subscription Agreement") with the Company to purchase that number of Subscriber's Acquired Shares specified therein (the "Transferee Acquired Shares"), which New Subscription Agreement shall be in substantially the same form as this Subscription Agreement; and

         (ii)  upon a Transferee's execution and delivery of a New Subscription Agreement, the number of Acquired Shares to be purchased by Subscriber hereunder shall be reduced by the total number of Transferee Acquired Shares to be purchased by the applicable Transferee pursuant to the applicable New Subscription Agreement, which reduction shall be evidenced by Subscriber and the Company amending Schedule B to this Subscription Agreement to reflect each transfer and to update the "Number of Acquired Shares subscribed for" and "Aggregate Purchase Price" on the signature page hereto to reflect such reduced number of Acquired Shares, and Subscriber shall be fully and unconditionally released from its obligation to purchase such Transferee Acquired Shares hereunder. For the avoidance of doubt, this Subscription Agreement need not be amended and restated in its entirety, but only Schedule B and Subscriber's signature page hereto need be so amended and updated and executed by each of Subscriber and the Company upon the occurrence of any such transfer of Transferee Acquired Shares.

        d.     All the agreements, representations and warranties made by each party hereto in this Subscription Agreement shall survive the Closing.

        e.     The Company may request from Subscriber such additional information as the Company may deem necessary to evaluate the eligibility of Subscriber to acquire the Acquired Shares, and Subscriber shall provide such information as may be reasonably requested, to the extent readily available and to the extent consistent with its internal policies and procedures.

        f.      This Subscription Agreement may not be modified, waived or terminated except by an instrument in writing, signed by the party against whom enforcement of such modification, waiver, or termination is sought.

        g.     This Subscription Agreement constitutes the entire agreement, and supersedes all other prior agreements, understandings, representations and warranties, both written and oral, among the parties, with respect to the subject matter hereof. This Subscription Agreement shall not confer any rights or remedies upon any person other than (i) the parties hereto and their respective successor and assigns and (ii) the persons entitled to indemnification under Section 5.

        h.     Except as otherwise provided herein, this Subscription Agreement shall be binding upon, and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives, and permitted assigns, and the agreements, representations, warranties,

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covenants and acknowledgments contained herein shall be deemed to be made by, and be binding upon, such heirs, executors, administrators, successors, legal representatives and permitted assigns.

        i.      If any provision of this Subscription Agreement shall be invalid, illegal or unenforceable, the validity, legality or enforceability of the remaining provisions of this Subscription Agreement shall not in any way be affected or impaired thereby and shall continue in full force and effect.

        j.      This Subscription Agreement may be executed in one or more counterparts (including by facsimile or electronic mail or in .pdf) and by different parties in separate counterparts, with the same effect as if all parties hereto had signed the same document. All counterparts so executed and delivered shall be construed together and shall constitute one and the same agreement.

        k.     The parties hereto agree that irreparable damage would occur in the event that any of the provisions of this Subscription Agreement were not performed in accordance with their specific terms or were otherwise breached. It is accordingly agreed that the parties shall be entitled to an injunction or injunctions to prevent breaches of this Subscription Agreement and to enforce specifically the terms and provisions of this Subscription Agreement, this being in addition to any other remedy to which such party is entitled at law, in equity, in contract, in tort or otherwise.

        l.      THIS SUBSCRIPTION AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO THE PRINCIPLES OF CONFLICTS OF LAWS THAT WOULD OTHERWISE REQUIRE THE APPLICATION OF THE LAW OF ANY OTHER STATE. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY SUBMITS TO THE EXCLUSIVE JURISDICTION OF THE STATE COURTS OF THE STATE OF NEW YORK, SEATED IN NEW YORK COUNTY AND ANY FEDERAL COURT SITTING IN THE SOUTHERN DISTRICT OF NEW YORK (AND ANY APPLICABLE COURTS OF APPEAL THERETO) OVER ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS SUBSCRIPTION AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY. EACH PARTY HERETO HEREBY WAIVES ANY RIGHT TO A JURY TRIAL IN CONNECTION WITH ANY LITIGATION PURSUANT TO THIS SUBSCRIPTION AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY.

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IN WITNESS WHEREOF, each of the Company and Subscriber has executed or caused this Subscription Agreement to be executed by its duly authorized representative as of the date set forth below.

CENTENNIAL RESOURCE DEVELOPMENT, INC.
By:	/s/ GEORGE S. GLYPHIS
	Name:	George S. Glyphis
	Title:	Chief Financial Officer

Date: November 27, 2016

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SUBSCRIBER: RIVERSTONE SILVERBACK HOLDINGS, L.P.

Signature of Subscriber:

Riverstone Silverback Holdings, L.P.

By: Riverstone VI REL Holdings GP, LLC, its general partner

By:	/s/ THOMAS J. WALKER
	Name:	Thomas J. Walker
	Title:	Managing Director

Date: November 27, 2016

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Name of Subscriber:

Riverstone Silverback Holdings, L.P. (Please print. Please indicate name and capacity of person signing above)	Name in which shares are to be registered (if different):
Email Address: twalker@riverstonellc.com Subscriber's EIN(1):
Business Address-Street: c/o Riverstone Holdings LLC 712 Fifth Avenue, 19th Floor City, State, Zip: New York, NY 10019	Mailing Address-Street (if different):
Attn: Thomas J. Walker	Attn:
Telephone No.: 212-993-0076	Telephone No.:
Facsimile No.: 212-993-0077	Facsimile No.:

Number of Acquired Shares subscribed for: $400 million of Acquired Shares, plus up to $100 million of Additional Acquired Shares, consisting of the following(2):

Class A Acquired Shares:
Series B Acquired Shares:

Price Per Class A Acquired Share: $14.54
Price Per Series B Acquired Share: $3,635.00 per share (or $14.54 per share on an as-converted basis)

Aggregate Purchase Price(3):
Excluding any Additional Acquired Shares: approximately $400.0 million

Including all Additional Acquired Shares: approximately $500.0 million

You must pay the Purchase Price by wire transfer of United States dollars in immediately available funds to the account specified by the Company in Annex B.

(1)

To be provided by Subscriber not less than 10 days prior to the Closing Date.

(2)

Such final number to be determined in accordance with Section 1 of the Subscription Agreement.

(3)

Such final amount to be determined based on final number of Acquired Shares determined in accordance with Section 1 of the Subscription Agreement.

A-16

TO BE EXECUTED UPON ANY ASSIGNMENT AND/OR REVISION TO ACQUIRED SHARES AND AGGREGATE PURCHASE PRICE SET FORTH ABOVE:

Number of Class A Acquired Shares, Series B Acquired Shares and Additional Acquired Shares subscribed for and Aggregate Purchase Price as of                        , 2016, accepted and agreed to as of this            day of                        , 2016 by:

RIVERSTONE SILVERBACK HOLDINGS, L.P.

By: Riverstone VI REL Holdings GP, LLC, its general partner

By:
	Name:	Thomas J. Walker
	Title:	Managing Director

CENTENNIAL RESOURCE DEVELOPMENT, INC.
By:
	Name:
	Title:

A-17

SCHEDULE A
ELIGIBILITY REPRESENTATIONS OF SUBSCRIBER

A.

QUALIFIED INSTITUTIONAL BUYER STATUS
(Please check the applicable subparagraphs):

1.

o    We are a "qualified institutional buyer" (as defined in Rule 144A under the Securities Act (a "QIB")).

2.

o    We are subscribing for the Acquired Shares as a fiduciary or agent for one or more investor accounts, and each owner of such account is a QIB.

B.

INSTITUTIONAL ACCREDITED INVESTOR STATUS
(Please check the applicable subparagraphs):

1.

o    We are an "accredited investor" (within the meaning of Rule 501(a) under the Securities Act or an entity in which all of the equity holders are accredited investors within the meaning of Rule 501(a) under the Securities Act, and have marked and initialed the appropriate box on the following page indicating the provision under which we qualify as an "accredited investor."

2.

o    We are not a natural person.

C.

AFFILIATE STATUS
(Please check the applicable box)

SUBSCRIBER:

o

is:



o

is not:

an "affiliate" (as defined in Rule 144 under the Securities Act) of the Company or acting on behalf of an affiliate of the Company.

Rule 501(a), in relevant part, states that an "accredited investor" shall mean any person who comes within any of the below listed categories, or who the issuer reasonably believes comes within any of the below listed categories, at the time of the sale of the securities to that person. Subscriber has indicated, by marking and initialing the appropriate box below, the provision(s) below which apply to Subscriber and under which Subscriber accordingly qualifies as an "accredited investor."

o

Any bank, registered broker or dealer, insurance company, registered investment company, business development company, or small business investment company;



o

Any plan established and maintained by a state, its political subdivisions, or any agency or instrumentality of a state or its political subdivisions for the benefit of its employees, if such plan has total assets in excess of $5,000,000;



o

Any employee benefit plan, within the meaning of the Employee Retirement Income Security Act of 1974, if a bank, insurance company, or registered investment adviser makes the investment decisions, or if the plan has total assets in excess of $5,000,000;



o

Any organization described in Section 501(c)(3) of the Internal Revenue Code, corporation, similar business trust, or partnership, not formed for the specific purpose of acquiring the securities offered, with total assets in excess of $5,000,000;

This page should be completed by Subscriber
and constitutes a part of the Subscription Agreement.

Schedule A-1

o

Any director, executive officer, or general partner of the issuer of the securities being offered or sold, or any director, executive officer, or general partner of a general partner of that issuer;



o

Any natural person whose individual net worth, or joint net worth with that person's spouse, at the time of his purchase exceeds $1,000,000. For purposes of calculating a natural person's net worth: (a) the person's primary residence must not be included as an asset; (b) indebtedness secured by the person's primary residence up to the estimated fair market value of the primary residence must not be included as a liability (except that if the amount of such indebtedness outstanding at the time of calculation exceeds the amount outstanding 60 days before such time, other than as a result of the acquisition of the primary residence, the amount of such excess must be included as a liability); and (c) indebtedness that is secured by the person's primary residence in excess of the estimated fair market value of the residence must be included as a liability;



o

Any natural person who had an individual income in excess of $200,000 in each of the two most recent years or joint income with that person's spouse in excess of $300,000 in each of those years and has a reasonable expectation of reaching the same income level in the current year;



o

Any trust with assets in excess of $5,000,000, not formed to acquire the securities offered, whose purchase is directed by a sophisticated person; or



o

Any entity in which all of the equity owners are accredited investors meeting one or more of the above tests.

Schedule A-2

SCHEDULE B
SCHEDULE OF TRANSFERS OF TRANSFEREE ACQUIRED SHARES

        The following transfers of a portion of the original Subscription amount have been made:

Date of Transfer Transferee Number of
Transferee Class A
Acquired Shares
Transferred Number of
Transferee Series B
Acquired Shares
Transferred Subscriber Revised
Subscription
Amount

Schedule B-1

TO BE EXECUTED UPON ANY ASSIGNMENT OR FINAL DETERMINATION OF ACQUIRED SHARES:

        Schedule B as of                        , 2016, accepted and agreed to as of this        day of                        , 2016 by:

RIVERSTONE SILVERBACK HOLDINGS, L.P.	CENTENNIAL RESOURCE DEVELOPMENT, INC.
By: Riverstone VI REL Holdings GP, LLC, its general partner
By:	By:
		Name:
		Title:

Schedule B-2

ANNEX A

Terms of Series B Preferred Stock

        Defined terms used in this Annex A shall have the meanings ascribed thereto in the Subscription Agreement to which this Annex A is annexed.

Issuer	Centennial Resource Development, Inc., a Delaware corporation.
Securities Offered	Shares of Series B Preferred Stock (including any Additional Acquired Shares that are shares of Series B Preferred Stock) up to the maximum number of Series B Acquired Shares subject to the Subscription Agreement, with a liquidation preference of $0.0001 per share (the "Liquidation Preference").
Liquidation Preference	In the event of a voluntary or involuntary liquidation, dissolution or winding up of the Company (each a "Liquidation Event"), holders of the Series B Preferred Stock will first be entitled to receive the Liquidation Preference per share, to the date of payment before any distribution of assets is made to holders of the Class A Common Stock or any other equity securities of the Company that by their terms rank junior to the Series B Preferred Stock as to liquidation rights.
	If, in the event of a Liquidation Event, after payment of any amounts to be paid in respect of any of the Company's equity securities that rank senior to the Series B Preferred Stock as to the payment of dividends or the distribution of assets upon the liquidation, dissolution or winding up of the Company ("Senior Securities"), the Company's assets available for distribution are insufficient to fully pay the liquidation payments owing to the holders of the Series B Preferred Stock and the holders of any of the Company's equity securities that rank on par with the Series B Preferred Stock as to the payment of dividends or the distribution of assets upon the liquidation, dissolution or winding up of the Company ("Parity Securities"), the holders of the Series B Preferred Stock and such Parity Securities will share ratably in the distribution of the Company's assets in proportion to the full liquidating distributions to which they would otherwise have been respectively entitled.
	After the payment of the Liquidation Preference to the holders of the Series B Preferred Stock (and payment of any amount to be paid in respect of any Senior Securities and any Parity Securities), the remaining assets of the Company shall be distributed ratably to the holders of the Company's common stock and the Series B Preferred Stock on a common equivalent basis (and any other participating equity securities of the Company).

	For all purposes hereunder, the following events shall not constitute a Liquidation Event (i) the merger or consolidation of the Company with any other entity, including a merger or consolidation in which the holders of the Series B Preferred Stock receive cash, securities or property for their shares, the sale, lease or exchange of all or substantially all of the Company's assets for cash, securities or other property, (ii) the conversion of the Company into another legal entity, or (iii) sale of all or substantially all of the assets of the Company to an affiliate of the Company in connection with a reorganization or liquidation.
Conversion	Each share of Series B Preferred Stock shall automatically convert into 250 shares of Class A Common Stock, subject to adjustments for stock splits, stock dividends, reorganization, recapitalizations and the like, upon the receipt by the Company of the Stockholder Approval.
Voting Rights	The holders of the Series B Preferred Stock shall have no voting rights, except as set forth below or as required by law. The affirmative vote of holders of a majority of the Series B Preferred Stock then outstanding, voting as a separate class, is required to (a) approve any amendment, alteration or repeal of any provision of the Certificate of Designation relating to the Series B Preferred Stock or the Company's charter that adversely affects the rights, preferences, privileges or voting powers of the Series B Preferred Stock or (b) authorize the issuance of any Senior Securities or Parity Securities. With respect to any matter on which the holders of Series B Preferred Stock are entitled to vote, each share of Series B Preferred Stock will be entitled to one vote on such matter.
Dividends	No dividends shall be payable on the Series B Preferred Stock; provided, that holders of the Series B Preferred Stock shall be entitled to pro rata participation in any dividends paid on the Company's common stock, on a common equivalent basis.
No Maturity Date	The Series B Preferred Stock is perpetual unless, as described below, redeemed by the Company at its option.
Redemption at the Company's Option	Beginning on the third anniversary of the Closing Date, the Company will have the right, but not the obligation, to redeem all (but not less than all) of each holder's shares of Series B Preferred Stock for a redemption price per share, determined on an as converted basis, equal to the average of the last reported sale price for a share of Class A Common Stock on NASDAQ for each of the last 10 consecutive trading days prior to the redemption date or, if such shares are no longer traded, at the fair market value of the Class A Common Stock, as determined in good faith by the Board of Directors of the Company.
Use of Proceeds	Proceeds of the offering will be used to pay a portion of the purchase price for the Transaction

ANNEX A-2

ANNEX B

Wire Instructions

Annex B

SUBSCRIPTION AGREEMENT

        This SUBSCRIPTION AGREEMENT is entered into this            day of December, 2016 (this "Subscription Agreement"), by and between Centennial Resource Development, Inc., a Delaware corporation (the "Company"), and the undersigned subscriber(s) (each individually, or if not more than one, as used herein, "Subscriber"). Each Subscriber is acting severally and not jointly with any other Subscriber, including, without limitation, the obligation to purchase Acquired Shares (defined below) hereunder and the representations and warranties of Subscriber hereunder (which are made by Subscriber as to itself only).

        WHEREAS, SB RS Holdings, LLC, a Delaware limited liability company ("Riverstone"), has entered into that certain Purchase and Sale Agreement, dated as of November 21, 2016 (the "Purchase Agreement"), pursuant to which Riverstone will acquire certain assets (the "Transferred Property") from Silverback Exploration, LLC and Silverback Operating, LLC, each a Delaware limited liability company (collectively "Silverback"), on the terms and subject to the conditions set forth therein;

        WHEREAS, pursuant to Section 11.5 of the Purchase Agreement, Riverstone has the right to assign (the "Assignment") all of its rights and obligations under the Purchase Agreement to Centennial Resource Production, LLC, a controlled subsidiary of the Company (the "Purchaser"), and the Purchaser, upon such Assignment, would acquire the Transferred Property instead of Riverstone, on the terms and subject to the conditions set forth therein (the "Transaction");

        WHEREAS, Riverstone, Riverstone Capital Services LLC, the Company and the Purchaser have entered into that certain Agreement to Assign, dated as of November 27, 2016 (the "Agreement to Assign"), pursuant to which Riverstone has agreed to make the Assignment, and the Purchaser has agreed to accept the Assignment, on the terms and subject to the conditions set forth therein;

        WHEREAS, to finance a portion of the Transaction, an affiliate of Riverstone (the "Riverstone Affiliate") has entered into that certain subscription agreement, dated as of November 27, 2016, pursuant to which the Riverstone Affiliate has agreed to purchase on the Closing Date (defined below) up to $500 million in a combination of shares of the Company's Class A common stock, par value $0.0001 per share (the "Class A Common Stock"), and shares of the Company's convertible Series B Preferred Stock, par value $0.0001 per share (the "Series B Preferred Stock"), in each case at a purchase price of $14.54 per share (on an as converted basis with respect to the Series B Preferred Stock), subject to adjustment as provided therein (the "Riverstone Subscription Agreement"), which commitment the Riverstone Affiliate may assign to one or more parties on or prior to the Closing Date;

        WHEREAS, the Series B Preferred Stock will be non-voting and will automatically convert into shares of Class A Common Stock on a 250-for-one basis, subject to adjustment as provided therein, upon approval by the stockholders of the Company of the issuance of such shares of Class A Common Stock, as required by the rules of The NASDAQ Capital Market ("NASDAQ");

        WHEREAS, to finance a portion of the Transaction, certain other "accredited investors" (as such term is defined in Rule 501 under the Securities Act of 1933, as amended (the "Securities Act")), have entered into subscription agreements with the Company substantially similar to this Subscription Agreement, pursuant to which such investors have agreed to purchase on the Closing Date, in the aggregate, that number of shares of Class A Common Stock that, together with the Acquired Shares (as defined below), equals an aggregate purchase price of approximately $480 million, at a purchase price of $14.54 per share (together with the Riverstone Subscription Agreement, the "Other Subscription Agreements"); and

        WHEREAS, to finance a portion of the Transaction, Subscriber desires to subscribe for and purchase from the Company that number of shares of Class A Common Stock set forth on its signature

B-1

page hereto (the "Acquired Shares"), for a purchase price of $14.54 per share, or the aggregate amount set forth on such signature page hereto (the "Purchase Price"), and the Company desires to issue and sell to Subscriber the Acquired Shares in consideration of the payment of the Purchase Price by or on behalf of Subscriber to the Company on or prior to the Closing (as defined below).

        NOW, THEREFORE, in consideration of the foregoing and the mutual representations, warranties and covenants, and subject to the conditions, herein contained, and intending to be legally bound hereby, the parties hereto hereby agree as follows:

        1.    Subscription.    Subject to the terms and conditions hereof, Subscriber hereby agrees to subscribe for and purchase, and the Company hereby agrees to issue and sell to Subscriber, upon the payment of the Purchase Price, the Acquired Shares (such subscription and issuance, the "Subscription").

2.    Closing.    

        a.     The closing of the Subscription contemplated hereby (the "Closing") is contingent upon the substantially concurrent consummation of the Transaction and shall occur immediately prior thereto. The Closing and the closing of the Transaction shall occur on December 30, 2016, subject to extension upon five (5) business days' prior written notice to Subscriber (such date, including as so extended, the "Closing Date"). At least three (3) business days prior to the Closing Date, Subscriber shall deliver to the Company, to be held in escrow until the Closing, the Purchase Price for the Acquired Shares by wire transfer of U.S. dollars in immediately available funds to the account specified by the Company upon five (5) business days' prior written notice to the Closing Date. Immediately prior to the closing of the Transaction on the Closing Date, (a) the Purchase Price shall be released from escrow automatically and without further action by the Company or Subscriber, and (b) upon such release, the Company shall deliver to Subscriber (i) the Acquired Shares in book entry form, free and clear of any liens or other restrictions whatsoever (other than those arising under state or federal securities laws), in the name of Subscriber (or its nominee in accordance with its delivery instructions) or to a custodian designated by Subscriber, as applicable, and (ii) written notice from the Company or its transfer agent evidencing the issuance to Subscriber of the Acquired Shares on and as of the Closing Date. In the event the Closing does not occur on the Closing Date, the Company shall promptly (but not later than one (1) business day thereafter) return the Purchase Price to Subscriber.

        b.     The Closing shall be subject to the conditions that, on the Closing Date:

          (i)  no suspension of the qualification of the Acquired Shares for offering or sale or trading in any jurisdiction, or initiation or threatening of any proceedings for any of such purposes, shall have occurred;

         (ii)  all representations and warranties of the Company and Subscriber contained in this Subscription Agreement shall be true and correct in all material respects (other than representations and warranties that are qualified as to materiality or Material Adverse Effect (as defined herein), which representations and warranties shall be true in all respects) at and as of the Closing Date, and consummation of the Closing shall constitute a reaffirmation by each of the Company and Subscriber of each of the representations, warranties and agreements of each such party contained in this Subscription Agreement as of the Closing Date, but in each case without giving effect to consummation of the Transaction;

        (iii)  the Company shall have performed, satisfied and complied in all material respects with all covenants, agreements and conditions required by this Subscription Agreement to be performed, satisfied or complied with by it at or prior to the Closing;

B-2

        (iv)  the Company shall have obtained approval of the NASDAQ to list the Acquired Shares, subject to official notice of issuance;

         (v)  no governmental authority shall have enacted, issued, promulgated, enforced or entered any judgment, order, law, rule or regulation (whether temporary, preliminary or permanent) which is then in effect and has the effect of making consummation of the transactions contemplated hereby illegal or otherwise restraining or prohibiting consummation of the transactions contemplated hereby, and no governmental authority shall have instituted or threatened in writing a proceeding seeking to impose any such restraint or prohibition;

        (vi)  the Company shall have received proceeds from debt or equity financings on terms satisfactory to the Company that, together with the proceeds from the sale of the Acquired Shares hereunder, will be sufficient for the Company to pay the purchase price for the Transaction pursuant to the Purchase Agreement and the Assignment on the Closing Date; and

       (vii)  the Transaction shall be consummated substantially concurrently with the Closing in accordance with the terms of the Purchase Agreement.

        c.     At the Closing, the parties hereto shall execute and deliver such additional documents and take such additional actions as the parties reasonably may deem to be practical and necessary in order to consummate the Subscription as contemplated by this Subscription Agreement.

        3.    Company Representations and Warranties.    The Company represents and warrants that:

        a.     Each of the Company and its subsidiaries, including the Purchaser, has been duly incorporated and is validly existing as a corporation or limited liability company in good standing under the laws of the State of Delaware, with corporate or limited liability company power and authority, as applicable, to (i) own, lease and operate its properties and conduct its business as presently conducted and (ii) with respect to the Company, to enter into, deliver and perform its obligations under this Subscription Agreement. The Company and each of its subsidiaries is duly qualified and in good standing to do business in each jurisdiction in which the business it is conducting, or the operation, ownership or leasing of its properties, makes such qualification necessary, other than where the failure to be duly incorporated, validly existing, or to so qualify or be in good standing has not had and would not be reasonably likely to have, individually or in the aggregate, a Material Adverse Effect.

        b.     The Acquired Shares have been duly authorized and, when issued and delivered to Subscriber against full payment therefor in accordance with the terms of this Subscription Agreement, the Acquired Shares will be validly issued, fully paid and non-assessable and will not have been issued in violation of or subject to any preemptive or similar rights created under the Company's second amended and restated certificate of incorporation, under the Delaware General Corporation Law.

        c.     There are no securities or instruments issued by or to which the Company is a party containing anti-dilution or similar provisions that will be triggered by the issuance of (i) the Acquired Shares, or (ii) the shares to be issued pursuant to any Other Subscription Agreement.

        d.     This Subscription Agreement has been duly authorized, executed and delivered by the Company and is enforceable against it in accordance with its terms, except as may be limited or otherwise affected by (i) bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or other laws relating to or affecting the rights of creditors generally, and (ii) principles of equity, whether considered at law or equity.

        e.     The execution and delivery of this Subscription Agreement, the issuance and sale of the Acquired Shares and the compliance by the Company with all of the provisions of this Subscription

B-3

Agreement and the consummation of the transactions contemplated herein will not conflict with or result in a breach or violation of any of the terms or provisions of, or constitute a default under, or result in the creation or imposition of any lien, charge or encumbrance upon any of the property or assets of the Company pursuant to the terms of (i) any indenture, mortgage, deed of trust, loan agreement, lease, license or other agreement or instrument to which the Company or any of its subsidiaries is a party or by which the Company or any of its subsidiaries is bound or to which any of the property or assets of the Company or any of its subsidiaries is subject, which would reasonably be expected to have a material adverse effect on the business, properties, financial condition, stockholders' equity or results of operations of the Company and its subsidiaries, taken as a whole (a "Material Adverse Effect"), or materially affect the validity of the Acquired Shares or the legal authority of the Company to comply in all material respects with the terms of this Subscription Agreement; (ii) the organizational documents of the Company or any of its subsidiaries; or (iii) any statute or any judgment, order, rule or regulation of any court or governmental agency or body, domestic or foreign, having jurisdiction over the Company, any of its subsidiaries or any of their respective properties that, in the case of clauses (i) and (iii), would reasonably be expected to have a Material Adverse Effect or affect the validity of the Acquired Shares or the legal authority of the Company to comply in all material respects with this Subscription Agreement.

        f.      The Company is not in default or violation (and no event has occurred which, with notice or the lapse of time or both, would constitute a default or violation) of any term, condition or provision of (i) the organizational documents of the Company or any of its subsidiaries, (ii) any loan or credit agreement, note, bond, mortgage, indenture, lease or other agreement, permit, franchise or license to which the Company or any of its subsidiaries is now a party or by which the Company's or any of its subsidiaries' properties or assets are bound or (iii) any statute or any judgment, order, rule or regulation of any court or governmental agency or body, domestic or foreign, having jurisdiction over the Company, any of its subsidiaries or any of their respective properties, except, in the case of clauses (ii) and (iii), for defaults or violations that have not had and would not be reasonably likely to have, individually or in the aggregate, a Material Adverse Effect.

        g.     The Company is not required to obtain any consent, waiver, authorization or order of, give any notice to, or make any filing or registration with, any court or other federal, state, local or other governmental authority, self-regulatory organization (including NASDAQ) or other person in connection with the execution, delivery and performance by the Company of this Subscription Agreement (including, without limitation, the issuance of the Acquired Shares), other than (i) the filing with the Securities and Exchange Commission (the "Commission") of the Registration Statement (as defined below), (ii) filings required by applicable state securities laws, (iii) if applicable, the filing of a Notice of Exempt Offering of Securities on Form D with the Commission under Regulation D of the Securities Act, (iv) the filings required in accordance with Section 8(m) of this Subscription Agreement; (v) those required by NASDAQ, including with respect to obtaining stockholder approval of the Proposal (as defined below), and (vi) the failure of which to obtain would not be reasonably likely to have, individually or in the aggregate, a Material Adverse Effect.

        h.     The authorized capital stock of the Company consists of 620,000,000 shares of common stock of the Company, par value $0.0001 per share ("Common Stock"), including (x) 600,000,000 shares of Class A Common Stock and (y) 20,000,000 shares of Class C Common Stock ("Class C Common Stock"), and 1,000,000 shares of preferred stock of the Company, par value $0.0001 per share ("Preferred Stock"). As of November 30, 2016: (i) 164,349,079 shares of Class A Common Stock, 19,155,921 shares of Class C Common Stock and one share of Preferred Stock, designated as the "Series A Preferred Stock," were issued and outstanding; (ii) 24,666,643 warrants, each

B-4

entitling the holder thereof to purchase one share of Class A Common Stock at an exercise price of $11.50 per share of Class A Common Stock ("Warrants") were issued and outstanding; (iii) 16,500,000 shares of Class A Common Stock were available for issuance under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan, of which awards with respect to 3,027,098 shares of Class A Common Stock were outstanding; and (iv) no indebtedness of the Company having the right to vote (or convertible into equity having the right to vote) on any matters on which the equityholders of the Company may vote was issued and outstanding. All (i) issued and outstanding shares of Common Stock and Preferred Stock have been duly authorized and validly issued, are fully paid and are non-assessable and are not subject to preemptive rights and (ii) outstanding Warrants have been duly authorized and validly issued, are fully paid and are not subject to preemptive rights. Except as set forth above and pursuant to the Other Subscription Agreements, there are no outstanding options, warrants or other rights to subscribe for, purchase or acquire from the Company any Common Stock or other equity interests in the Company (collectively, "Equity Interests") or securities convertible into or exchangeable or exercisable for Equity Interests.

        i.      The Company has made available to Subscriber (including via the Commission's EDGAR system) a copy of each form, report, statement, schedule, prospectus, proxy, registration statement and other document filed by the Company with the Commission since its initial registration of the Class A Common Stock (the "SEC Documents"). None of the SEC Documents filed under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), contained, when filed or, if amended, as of the date of such amendment with respect to those disclosures that are amended, any untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein, in light of the circumstances under which they were made, not misleading; provided, that the Company makes no such representation or warranty with respect to any information relating to Silverback or any of its affiliates included in any SEC Document or filed as an exhibit thereto. The Company has timely filed each report, statement, schedule, prospectus, and registration statement that the Company was required to file with the Commission since its inception. There are no material outstanding or unresolved comments in comment letters from the Commission Staff with respect to any of the SEC Documents.

        j.      The financial statements of the Company included in the SEC Documents complied as to form in all material respects with Regulation S-X of the Commission, were prepared in accordance with U.S. generally accepted accounting principles ("GAAP") applied on a consistent basis during the periods involved (except as may be indicated in the notes thereto or, in the case of the unaudited statements, as permitted by Rule 10-01 of Regulation S-X of the Commission) and fairly present in all material respects in accordance with applicable requirements of GAAP (subject, in the case of the unaudited statements, to normal year-end audit adjustments) the financial position of the Company as of their respective dates and the results of operations and the cash flows of the Company for the periods presented therein.

        k.     The Company has not received any written communication since December 31, 2015 from a governmental entity that alleges that the Company or any of its subsidiaries is not in compliance with or is in default or violation of any applicable law, except where such non-compliance, default or violation would not, individually or in the aggregate, be reasonably likely to have a Material Adverse Effect.

        l.      Except for such matters as have not had and would not be reasonably likely to have, individually or in the aggregate, a Material Adverse Effect, there is no (i) proceeding pending, or, to the knowledge of the Company, threatened against the Company or any of its subsidiaries or (ii) judgment, decree, injunction, ruling or order of any governmental entity or arbitrator outstanding against the Company or any of its subsidiaries.

B-5

        m.    The lists of exhibits contained in the SEC Documents set forth a true and complete list, as of the date of this Subscription Agreement, of each agreement to which the Company or any of its subsidiaries is a party (other than the Agreement to Assign, this Subscription Agreement and the Other Subscription Agreements) that is of a type that would be required to be included as an exhibit to a Registration Statement on Form S-1 pursuant to Items 601(b)(2), (4), (9) or (10) of Regulation S-K of the Commission if such a registration statement were filed by the Company on the date of this Subscription Agreement.

        n.     The issued and outstanding shares of Class A Common Stock are registered pursuant to Section 12(b) of the Exchange Act and are listed for trading on the NASDAQ under the symbol "CDEV". There is no suit, action, proceeding or investigation pending or, to the knowledge of the Company, threatened against the Company by NASDAQ or the Commission with respect to any intention by such entity to deregister the Class A Common Stock or prohibit or terminate the listing of the Class A Common Stock on NASDAQ. The Company has taken no action that is designed to terminate the registration of the Class A Common Stock under the Exchange Act.

        o.     All material Tax Returns (as defined in the Purchase Agreement) required to be filed by or with respect to the Company and its subsidiaries have been duly and timely filed (taking into account extension of time for filing) with the appropriate governmental entity, and all such Tax Returns were true, correct and complete in all material respects. The Company and its subsidiaries have paid all Taxes (as defined in the Purchase Agreement) and other assessments due, whether or not disputed. The Company and its subsidiaries do not have any liabilities for Taxes of any other person or entity by contract, as a transferee or successor, under U.S. Treasury Regulation Section 1.1502-6 or analogous state, county, local or foreign provision or otherwise.

        p.     The Company is not, and immediately after receipt of payment for the Acquired Shares will not be, an "investment company" within the meaning of the Investment Company Act of 1940, as amended.

        q.     Assuming the accuracy of Subscriber's representations and warranties set forth in Section 4 of this Subscription Agreement, no registration under the Securities Act is required for the offer and sale of the Acquired Shares by the Company to Subscriber.

        r.     Neither the Company nor any person acting on its behalf has engaged or will engage in any form of general solicitation or general advertising (within the meaning of Regulation D) in connection with any offer or sale of the Acquired Shares.

        4.    Subscriber Representations and Warranties.    Subscriber represents and warrants that:

        a.     Subscriber has been duly formed or incorporated and is validly existing in good standing under the laws of its jurisdiction of incorporation or formation, with power and authority to enter into, deliver and perform its obligations under this Subscription Agreement.

        b.     This Subscription Agreement has been duly authorized, executed and delivered by Subscriber. This Subscription Agreement is enforceable against Subscriber in accordance with its terms, except as may be limited or otherwise affected by (i) bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or other laws relating to or affecting the rights of creditors generally, and (ii) principles of equity, whether considered at law or equity.

        c.     The execution, delivery and performance by Subscriber of this Subscription Agreement and the consummation of the transactions contemplated herein will not conflict with or result in a breach or violation of any of the terms or provisions of, or constitute a default under, or result in the creation or imposition of any lien, charge or encumbrance upon any of the property or assets of Subscriber pursuant to the terms of (i) any indenture, mortgage, deed of trust, loan agreement, lease, license or other agreement or instrument to which Subscriber is a party or by which

B-6

Subscriber is bound or to which any of the property or assets of Subscriber is subject, which would reasonably be expected to have a material adverse effect on the business, properties, financial condition, stockholders' equity or results of operations of Subscriber (a "Subscriber Material Adverse Effect") or materially affect the legal authority of Subscriber to comply in all material respects with the terms of this Subscription Agreement; (ii) the organizational documents of Subscriber; or (iii) any statute or any judgment, order, rule or regulation of any court or governmental agency or body, domestic or foreign, having jurisdiction over Subscriber or any of its properties that, in the case of clauses (i) and (iii), would reasonably be expected to have a Subscriber Material Adverse Effect or affect the legal authority of Subscriber to comply in all material respects with this Subscription Agreement.

        d.     Subscriber (i) is a "qualified institutional buyer" (as defined in Rule 144A under the Securities Act) or an institutional "accredited investor" (within the meaning of Rule 501(a) under the Securities Act) satisfying the applicable requirements set forth on Schedule A, (ii) is acquiring the Acquired Shares only for its own account and not for the account of others, or if Subscriber is subscribing for the Acquired Shares as a fiduciary or agent for one or more investor accounts, each owner of such account is a qualified institutional buyer and Subscriber has full investment discretion with respect to each such account, and the full power and authority to make the acknowledgements, representations and agreements herein on behalf of each owner of each such account, and (iii) is not acquiring the Acquired Shares with a view to, or for offer or sale in connection with, any distribution thereof in violation of the Securities Act (and shall provide the requested information on Schedule A following the signature page hereto). Subscriber is not an entity formed for the specific purpose of acquiring the Acquired Shares.

        e.     Subscriber understands that the Acquired Shares are being offered in a transaction not involving any public offering within the meaning of the Securities Act and that the Acquired Shares have not been registered under the Securities Act. Subscriber understands that the Acquired Shares may not be resold, transferred, pledged or otherwise disposed of by Subscriber absent an effective registration statement under the Securities Act, except (i) to the Company or a subsidiary thereof, (ii) to non-U.S. persons pursuant to offers and sales that occur outside the United States within the meaning of Regulation S under the Securities Act or (iii) pursuant to another applicable exemption from the registration requirements of the Securities Act, and, in each of cases (i) and (iii), in accordance with any applicable securities laws of the states and other jurisdictions of the United States, and that any certificates representing the Acquired Shares shall contain a legend to such effect. Subscriber acknowledges that the Acquired Shares will not be eligible for resale pursuant to Rule 144A promulgated under the Securities Act. Subscriber understands and agrees that the Acquired Shares will be subject to transfer restrictions and, as a result of these transfer restrictions, Subscriber may not be able to readily resell the Acquired Shares and may be required to bear the financial risk of an investment in the Acquired Shares for an indefinite period of time. Subscriber understands that it has been advised to consult legal counsel prior to making any offer, resale, pledge or transfer of any of the Acquired Shares.

        f.      Subscriber understands and agrees that Subscriber is purchasing the Acquired Shares directly from the Company. Subscriber further acknowledges that there have been no representations, warranties, covenants and agreements made to Subscriber by the Company, Silverback or any of their respective officers or directors, expressly or by implication, other than those representations, warranties, covenants and agreements of the Company included in this Subscription Agreement.

        g.     Subscriber represents and warrants that its acquisition and holding of the Acquired Shares will not constitute or result in a non-exempt prohibited transaction under Section 406 of the Employee Retirement Income Security Act of 1974, as amended, Section 4975 of the Internal Revenue Code of 1986, as amended, or any applicable similar law.

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        h.     In making its decision to purchase the Acquired Shares, Subscriber represents that it has relied solely upon independent investigation made by Subscriber. Subscriber acknowledges and agrees that Subscriber has received such information as Subscriber deems necessary in order to make an investment decision with respect to the Acquired Shares, including with respect to the Company, Silverback and the Transaction. Subscriber represents and agrees that Subscriber and Subscriber's professional advisor(s), if any, have had the full opportunity to ask such questions, receive such answers and obtain such information as Subscriber and such undersigned's professional advisor(s), if any, have deemed necessary to make an investment decision with respect to the Acquired Shares.

        i.      Subscriber became aware of this offering of the Acquired Shares solely by means of direct contact between Subscriber and the Company or by means of contact from Citigroup Global Markets Inc. ("Citi"), acting as placement agent for the Company, and the Acquired Shares were offered to Subscriber solely by direct contact between Subscriber and the Company or by contact between Subscriber and Citi. Subscriber did not become aware of this offering of the Acquired Shares, nor were the Acquired Shares offered to Subscriber, by any other means. Subscriber acknowledges that the Company represents and warrants that the Acquired Shares (i) were not offered by any form of general solicitation or general advertising and (ii) are not being offered in a manner involving a public offering under, or in a distribution in violation of, the Securities Act, or any state securities laws.

        j.      Subscriber acknowledges that it is aware that there are substantial risks incident to the purchase and ownership of the Acquired Shares. Subscriber has such knowledge and experience in financial and business matters as to be capable of evaluating the merits and risks of an investment in the Acquired Shares, and Subscriber has sought such accounting, legal and tax advice as Subscriber has considered necessary to make an informed investment decision.

        k.     Subscriber represents and acknowledges that Subscriber has adequately analyzed and fully considered the risks of an investment in the Acquired Shares and determined that the Acquired Shares are a suitable investment for Subscriber and that Subscriber is able at this time and in the foreseeable future to bear the economic risk of a total loss of Subscriber's investment in the Company. Subscriber acknowledges specifically that a possibility of total loss exists.

        l.      Subscriber understands and agrees that no federal or state agency has passed upon or endorsed the merits of the offering of the Acquired Shares or made any findings or determination as to the fairness of this investment.

        m.    Subscriber represents and warrants that Subscriber is not (i) a person or entity named on the List of Specially Designated Nationals and Blocked Persons administered by the U.S. Treasury Department's Office of Foreign Assets Control ("OFAC") or in any Executive Order issued by the President of the United States and administered by OFAC ("OFAC List"), or a person or entity prohibited by any OFAC sanctions program, (ii) a Designated National as defined in the Cuban Assets Control Regulations, 31 C.F.R. Part 515, or (iii) a non-U.S. shell bank or providing banking services indirectly to a non-U.S. shell bank (collectively, a "Prohibited Investor"). Subscriber agrees to provide law enforcement agencies, if requested thereby, such records as required by applicable law, provided that Subscriber is permitted to do so under applicable law. Subscriber represents that if it is a financial institution subject to the Bank Secrecy Act (31 U.S.C. Section 5311 et seq.) (the "BSA"), as amended by the USA PATRIOT Act of 2001 (the "PATRIOT Act"), and its implementing regulations (collectively, the "BSA/PATRIOT Act"), that Subscriber maintains policies and procedures reasonably designed to comply with applicable obligations under the BSA/PATRIOT Act. Subscriber also represents that, to the extent required, it maintains policies and procedures reasonably designed for the screening of its investors against the OFAC sanctions programs, including the OFAC List. Subscriber further represents and warrants that, to the extent

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required, it maintains policies and procedures reasonably designed to ensure that the funds held by Subscriber and used to purchase the Acquired Shares were legally derived.

5.    Registration Rights.    

        a.     The Company agrees that, within seventy-five (75) calendar days after the Closing, the Company will file with the Commission (at the Company's sole cost and expense) a registration statement registering the resale of the Acquired Shares (the "Registration Statement"), and the Company shall use its commercially reasonable efforts to have the Registration Statement declared effective as soon as practicable after the filing thereof, but no later than the earlier of (i) the 90th calendar day following the filing thereof and (ii) the 10th business day after the date the Company is notified (orally or in writing, whichever is earlier) by the Commission that the Registration Statement will not be "reviewed" or will not be subject to further review (such earlier date, the "Effectiveness Deadline"); provided, however, that the Company's obligations to include the Acquired Shares in the Registration Statement are contingent upon Subscriber furnishing in writing to the Company such information regarding Subscriber, the securities of the Company held by Subscriber and the intended method of disposition of the Acquired Shares as shall be reasonably requested by the Company to effect the registration of the Acquired Shares, and shall execute such documents in connection with such registration as the Company may reasonably request that are customary of a selling stockholder in similar situations.

        b.     The Company shall, notwithstanding any termination of this Subscription Agreement, indemnify, defend and hold harmless Subscriber (to the extent a seller under the Registration Statement), the officers, directors, agents, partners, members, managers, stockholders, affiliates, employees and investment advisers of each of them, each person who controls Subscriber (within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act) and the officers, directors, partners, members, managers, stockholders, agents, affiliates, employees and investment advisers of each such controlling person, to the fullest extent permitted by applicable law, from and against any and all losses, claims, damages, liabilities, costs (including, without limitation, reasonable costs of preparation and investigation and reasonable attorneys' fees) and expenses (collectively, "Losses"), as incurred, that arise out of or are based upon (i) any untrue or alleged untrue statement of a material fact contained in the Registration Statement, any prospectus included in the Registration Statement or any form of prospectus or in any amendment or supplement thereto or in any preliminary prospectus, or arising out of or relating to any omission or alleged omission to state a material fact required to be stated therein or necessary to make the statements therein (in the case of any prospectus or form of prospectus or supplement thereto, in light of the circumstances under which they were made) not misleading, or (ii) any violation or alleged violation by the Company of the Securities Act, Exchange Act or any state securities law or any rule or regulation thereunder, in connection with the performance of its obligations under this Section 5, except to the extent, but only to the extent, that such untrue statements, alleged untrue statements, omissions or alleged omissions are based solely upon information regarding Subscriber furnished in writing to the Company by Subscriber expressly for use therein. The Company shall notify Subscriber promptly of the institution, threat or assertion of any proceeding arising from or in connection with the transactions contemplated by this Section 5 of which the Company is aware. Such indemnity shall remain in full force and effect regardless of any investigation made by or on behalf of an indemnified party and shall survive the transfer of the Acquired Shares by Subscriber.

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        c.     Subscriber shall, severally and not jointly with any other subscriber, indemnify and hold harmless the Company, its directors, officers, agents and employees, each person who controls the Company (within the meaning of Section 15 of the Securities Act and Section 20 of the Exchange Act), and the directors, officers, agents or employees of such controlling persons, to the fullest extent permitted by applicable law, from and against all Losses, as incurred, arising out of or are based upon any untrue or alleged untrue statement of a material fact contained in any Registration Statement, any prospectus included in the Registration Statement, or any form of prospectus, or in any amendment or supplement thereto or in any preliminary prospectus, or arising out of or relating to any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein (in the case of any prospectus, or any form of prospectus or supplement thereto, in light of the circumstances under which they were made) not misleading to the extent, but only to the extent, that such untrue statements or omissions are based solely upon information regarding Subscriber furnished in writing to the Company by Subscriber expressly for use therein. In no event shall the liability of Subscriber be greater in amount than the dollar amount of the net proceeds received by Subscriber upon the sale of the Acquired Shares giving rise to such indemnification obligation.

        6.    Termination.    This Subscription Agreement shall terminate and be void and of no further force and effect, and all rights and obligations of the parties hereunder shall terminate without any further liability on the part of any party in respect thereof, upon the earlier to occur of (a) such date and time as the Purchase Agreement is terminated in accordance with its terms, (b) the consummation of the transactions contemplated by the Purchase Agreement pursuant to the terms thereof by Riverstone without the Assignment to the Purchaser pursuant to the terms of the Agreement to Assign, (c) upon the mutual written agreement of each of the parties hereto to terminate this Subscription Agreement, (d) if any of the conditions to Closing set forth in Section 2 of this Subscription Agreement are not satisfied on or prior to the Closing and, as a result thereof, the transactions contemplated by this Subscription Agreement are not consummated at the Closing or (e) January 31, 2017, if the Closing has not occurred by such date (subject to extension to a date no later than February 15, 2017 if the Purchase Agreement "Outside Date" (as defined therein) is correspondingly extended and the Company provides Subscriber notice of such extension or anticipated extension at least two (2) business days prior to January 31, 2017); provided, that nothing herein will relieve any party from liability for any willful breach hereof prior to the time of termination, and each party will be entitled to any remedies at law or in equity to recover losses, liabilities or damages arising from such breach. The Company shall notify Subscriber of the termination of the Purchase Agreement promptly after the termination of such agreement or the consummation of the transactions by Riverstone without the Assignment to the Purchaser promptly after such consummation.

        7.    Restrictions on Transfer and Voting.

        a.     As used in this Section 7, the following terms shall have the respective meanings set forth below:

          (i)  "Beneficially Own", "Beneficial Ownership" or "beneficial owner" with respect to any securities means having "beneficial ownership" of such securities (as determined pursuant to Rule 13d-3 under the Exchange Act), including pursuant to any agreement, arrangement or understanding, whether or not in writing.

         (ii)  "Proposal" means a proposal to be voted upon by the stockholders of the Company to permit the issuance of all of the shares of Class A Common Stock issuable upon conversion of the Series B Preferred Stock held by the Riverstone Affiliate upon conversion thereof, as required by the NASDAQ rules.

        (iii)  "Record Date" means a date selected by the Board of Directors of the Company for the purpose of determining the stockholders of the Company entitled to vote at a duly

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convened special meeting of the stockholders to approve the Proposal (the "Special Meeting"); provided, that the Record Date shall occur no later than 105 days following the Closing Date.

        b.     Subscriber shall not, directly or indirectly, on or prior to the business day following the Record Date (i) sell, transfer, assign or otherwise dispose of any or all of the Acquired Shares or Beneficial Ownership or voting power thereof or therein (including by operation of law) or (ii) grant any proxies or powers of attorney, deposit any Acquired Shares into a voting trust or enter into a voting agreement with respect to any Acquired Shares (any such action in clauses (i) or (ii) above, a "Transfer"). Any Transfer in violation of this provision shall be void.

        c.     Subscriber further agrees to authorize the Company to notify the Company's transfer agent that there is a stop transfer order with respect to all of the Acquired Shares; provided, however, that any such stop transfer order shall terminate on the business day following the Record Date.

        d.     The Company hereby notifies Subscriber that, pursuant to NASDAQ Rule 5635 and IM-5635-2. Interpretative Material Regarding the Use of Share Caps to Comply with Rule 5635, the Acquired Shares will not be entitled to vote to approve the Proposal at the Special Meeting or any adjournment thereof.

        8.    Miscellaneous.

        a.     Subscriber acknowledges that the Company and others will rely on the acknowledgments, understandings, agreements, representations and warranties contained in this Subscription Agreement. Prior to the Closing, Subscriber agrees to promptly notify the Company if any of the acknowledgments, understandings, agreements, representations and warranties of Subscriber set forth herein are no longer accurate in all material respects. The Company acknowledges that Subscriber and others will rely on the acknowledgments, understandings, agreements, representations and warranties contained in this Subscription Agreement. Prior to the Closing, the Company agrees to promptly notify Subscriber if any of the acknowledgments, understandings, agreements, representations and warranties of the Company set forth herein are no longer accurate in all material respects.

        b.     Each of the Company and Subscriber is entitled to rely upon this Subscription Agreement and is irrevocably authorized to produce this Subscription Agreement or a copy hereof to any interested party in any administrative or legal proceeding or official inquiry with respect to the matters covered hereby.

        c.     Neither this Subscription Agreement nor any rights that may accrue to Subscriber hereunder (other than the Acquired Shares acquired hereunder, if any) may be transferred or assigned. Neither this Subscription Agreement nor any rights that may accrue to the Company hereunder may be transferred or assigned.

        d.     All the agreements, representations and warranties made by each party hereto in this Subscription Agreement shall survive the Closing.

        e.     The Company may request from Subscriber such additional information as the Company may deem necessary to evaluate the eligibility of Subscriber to acquire the Acquired Shares, and Subscriber shall provide such information as may be reasonably requested, to the extent readily available and to the extent consistent with its internal policies and procedures.

        f.      This Subscription Agreement may not be modified, waived or terminated except by an instrument in writing, signed by the party against whom enforcement of such modification, waiver, or termination is sought.

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        g.     This Subscription Agreement constitutes the entire agreement, and supersedes all other prior agreements, understandings, representations and warranties, both written and oral, among the parties, with respect to the subject matter hereof. This Subscription Agreement shall not confer any rights or remedies upon any person other than (i) the parties hereto and their respective successor and assigns and (ii) the persons entitled to indemnification under Section 5.

        h.     Except as otherwise provided herein, this Subscription Agreement shall be binding upon, and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives, and permitted assigns, and the agreements, representations, warranties, covenants and acknowledgments contained herein shall be deemed to be made by, and be binding upon, such heirs, executors, administrators, successors, legal representatives and permitted assigns.

        i.      If any provision of this Subscription Agreement shall be invalid, illegal or unenforceable, the validity, legality or enforceability of the remaining provisions of this Subscription Agreement shall not in any way be affected or impaired thereby and shall continue in full force and effect.

        j.      This Subscription Agreement may be executed in one or more counterparts (including by facsimile or electronic mail or in .pdf) and by different parties in separate counterparts, with the same effect as if all parties hereto had signed the same document. All counterparts so executed and delivered shall be construed together and shall constitute one and the same agreement.

        k.     The parties hereto agree that irreparable damage would occur in the event that any of the provisions of this Subscription Agreement were not performed in accordance with their specific terms or were otherwise breached. It is accordingly agreed that the parties shall be entitled to an injunction or injunctions to prevent breaches of this Subscription Agreement and to enforce specifically the terms and provisions of this Subscription Agreement, this being in addition to any other remedy to which such party is entitled at law, in equity, in contract, in tort or otherwise.

        l.      THIS SUBSCRIPTION AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO THE PRINCIPLES OF CONFLICTS OF LAWS THAT WOULD OTHERWISE REQUIRE THE APPLICATION OF THE LAW OF ANY OTHER STATE. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY SUBMITS TO THE EXCLUSIVE JURISDICTION OF THE STATE COURTS OF THE STATE OF NEW YORK, SEATED IN NEW YORK COUNTY AND ANY FEDERAL COURT SITTING IN THE SOUTHERN DISTRICT OF NEW YORK (AND ANY APPLICABLE COURTS OF APPEAL THERETO) OVER ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS SUBSCRIPTION AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY. EACH PARTY HERETO HEREBY WAIVES ANY RIGHT TO A JURY TRIAL IN CONNECTION WITH ANY LITIGATION PURSUANT TO THIS SUBSCRIPTION AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY.

        m.    The Company shall, by 9:00 a.m., New York City time, on the first (1st) business day immediately following the date of this Subscription Agreement, issue one or more press releases or file with the Commission a Current Report on Form 8-K (collectively, the "Disclosure Document") disclosing, to the extent not previously publicly disclosed, all material terms of the transactions contemplated hereby (and by the Other Subscription Agreements), the Transaction and any other material, nonpublic information that the Company has provided to Subscriber at any time prior to the filing of the Disclosure Document. From and after the issuance of the Disclosure Document, to the Company's knowledge, Subscriber shall not be in possession of any material, non-public information received from the Company or any of its officers, directors, employees or Citi.

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IN WITNESS WHEREOF, each of the Company and Subscriber has executed or caused this Subscription Agreement to be executed by its duly authorized representative as of the date set forth below.

CENTENNIAL RESOURCE DEVELOPMENT, INC.
By:
	Name:
	Title:

Date: December     , 2016

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SUBSCRIBER:

By:
By:
	Name:
	Title:
Date: December     , 2016

	Number of Acquired Shares subscribed for:
Name in which shares are to be registered (if different):
	Price Per Acquired Share: $14.54
	Aggregate Purchase Price: $
Email Address:
Business Address-Street:	Mailing Address-Street (if different):
City, State, Zip:	City, State, Zip:
Attn:	Attn:
Telephone No.:	Telephone No.:
Facsimile No.:	Facsimile No.:

        You must pay the Purchase Price by wire transfer of United States dollars in immediately available funds to the account specified by the Company.

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SCHEDULE A
ELIGIBILITY REPRESENTATIONS OF SUBSCRIBER

A.

QUALIFIED INSTITUTIONAL BUYER STATUS
(Please check the applicable subparagraphs):

1.

o    We are a "qualified institutional buyer" (as defined in Rule 144A under the Securities Act (a "QIB")).

2.

o    We are subscribing for the Acquired Shares as a fiduciary or agent for one or more investor accounts, and each owner of such account is a QIB.

B.

INSTITUTIONAL ACCREDITED INVESTOR STATUS
(Please check the applicable subparagraphs):

1.

o    We are an "accredited investor" (within the meaning of Rule 501(a) under the Securities Act or an entity in which all of the equity holders are accredited investors within the meaning of Rule 501(a) under the Securities Act, and have marked and initialed the appropriate box on the following page indicating the provision under which we qualify as an "accredited investor."

2.

o    We are not a natural person.

C.

AFFILIATE STATUS
(Please check the applicable box)

SUBSCRIBER:

o

is:



o

is not:

an "affiliate" (as defined in Rule 144 under the Securities Act) of the Company or acting on behalf of an affiliate of the Company.

Rule 501(a), in relevant part, states that an "accredited investor" shall mean any person who comes within any of the below listed categories, or who the issuer reasonably believes comes within any of the below listed categories, at the time of the sale of the securities to that person. Subscriber has indicated, by marking and initialing the appropriate box below, the provision(s) below which apply to Subscriber and under which Subscriber accordingly qualifies as an "accredited investor."

o

Any bank, registered broker or dealer, insurance company, registered investment company, business development company, or small business investment company;



o

Any plan established and maintained by a state, its political subdivisions, or any agency or instrumentality of a state or its political subdivisions for the benefit of its employees, if such plan has total assets in excess of $5,000,000;



o

Any employee benefit plan, within the meaning of the Employee Retirement Income Security Act of 1974, if a bank, insurance company, or registered investment adviser makes the investment decisions, or if the plan has total assets in excess of $5,000,000;



o

Any organization described in Section 501(c)(3) of the Internal Revenue Code, corporation, similar business trust, or partnership, not formed for the specific purpose of acquiring the securities offered, with total assets in excess of $5,000,000;

This page should be completed by Subscriber
and constitutes a part of the Subscription Agreement.

Schedule A-1

o

Any director, executive officer, or general partner of the issuer of the securities being offered or sold, or any director, executive officer, or general partner of a general partner of that issuer;



o

Any natural person whose individual net worth, or joint net worth with that person's spouse, at the time of his purchase exceeds $1,000,000. For purposes of calculating a natural person's net worth: (a) the person's primary residence must not be included as an asset; (b) indebtedness secured by the person's primary residence up to the estimated fair market value of the primary residence must not be included as a liability (except that if the amount of such indebtedness outstanding at the time of calculation exceeds the amount outstanding 60 days before such time, other than as a result of the acquisition of the primary residence, the amount of such excess must be included as a liability); and (c) indebtedness that is secured by the person's primary residence in excess of the estimated fair market value of the residence must be included as a liability;



o

Any natural person who had an individual income in excess of $200,000 in each of the two most recent years or joint income with that person's spouse in excess of $300,000 in each of those years and has a reasonable expectation of reaching the same income level in the current year;



o

Any trust with assets in excess of $5,000,000, not formed to acquire the securities offered, whose purchase is directed by a sophisticated person; or



o

Any entity in which all of the equity owners are accredited investors meeting one or more of the above tests.

Schedule A-2

Annex C

CERTIFICATE OF DESIGNATION OF
SERIES B PREFERRED STOCK OF
CENTENNIAL RESOURCE DEVELOPMENT, INC.

        Centennial Resource Development, Inc., a Delaware corporation (the "Corporation"), hereby certifies that, pursuant to the provisions of Sections 103, 141 and 151 of the General Corporation Law of the State of Delaware, on December 28, 2016, the board of directors of the Corporation (the "Board") adopted the resolution shown immediately below, which resolution is now, and at all times since its date of adoption, has been in full force and effect:

        RESOLVED, that pursuant to the provisions of the Second Amended and Restated Certificate of Incorporation of the Corporation (as such may be amended, modified or restated from time to time, the "Amended and Restated Certificate") (which authorizes 1,000,000 shares of preferred stock, par value $0.0001 per share (the "Preferred Stock")), and the authority thereby vested in the Board, a series of Preferred Stock be, and it hereby is, created, and that the designation and number of shares of such series, and the voting and other powers, preferences and relative, participating, optional or other rights, and the qualifications, limitations and restrictions thereof are as set forth in the Amended and Restated Certificate and this Certificate of Designation, as it may be amended from time to time (the "Certificate of Designation") as follows:

        SECTION 1.    Designation, Number of Shares and Liquidation Preference.    Pursuant to the Amended and Restated Certificate, there is hereby created out of the authorized and unissued shares of Preferred Stock a series of Preferred Stock consisting of one hundred and four thousand four hundred (104,400) shares of Preferred Stock designated as "Series B Preferred Stock" (the "Series B Preferred Stock"). The liquidation preference of each share of Series B Preferred Stock (the "Liquidation Preference") shall be $0.0001.

        SECTION 2.    Rank.    The Series B Preferred Stock shall, as to the payment of dividends and the distribution of assets upon the liquidation, dissolution or winding up of the Corporation, whether voluntary or involuntary, rank (a) junior to each class or series of a class of capital stock of the Corporation the terms of which expressly provide that the shares thereof rank senior to the Series B Preferred Stock as to the payment of dividends or the distribution of assets upon liquidation, dissolution or winding up of the Corporation, whether voluntary or involuntary (the "Senior Securities"); (b) prior to each class of the Corporation's Common Stock, par value $0.0001 per share (including the Corporation's Class A Common Stock, par value $0.0001 per share (the "Class A Common Stock") and Class C Common Stock, par value $0.0001 per share), the Corporation's Series A Preferred Stock, par value $0.0001 per share, and any other capital stock of the Corporation (other than any other class or series of a class of capital stock of the Corporation the terms of which expressly provide that the shares thereof rank senior or on a parity as to the payment of dividends or the distribution of assets upon the liquidation, dissolution or winding up of the Corporation, whether voluntary or involuntary, with the shares of the Series B Preferred Stock) (such securities, other than those described in the immediately preceding parenthetical clause, collectively referred to herein as the "Junior Securities"); and (c) on a parity with each other class or series of a class of capital stock of the Corporation the terms of which expressly provide that the shares thereof rank on a parity as to the payment of dividends or the distribution of assets upon liquidation, dissolution or winding up of the Corporation, whether voluntary or involuntary, with the shares of the Series B Preferred Stock (the "Parity Securities").

        SECTION 3.    Maturity.    Except as provided in Section 9, the Series B Preferred Stock shall be perpetual.

        SECTION 4    Uncertificated Shares.    The shares of Series B Preferred Stock and any shares of Class A Common Stock issuable upon the conversion of the Series B Preferred Stock (the "Conversion

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Shares") in accordance with Section 8 shall be in uncertificated, book-entry form as permitted by the bylaws of the Corporation and the Delaware General Corporation Law.

        SECTION 5    Voting.    The holders of the Series B Preferred Stock shall have no voting rights, except as set forth in this Section 5 or as required by law. The affirmative vote of holders of a majority of the Series B Preferred Stock then outstanding, voting as a separate class, shall be required to (a) approve any amendment, alteration or repeal of any provision of this Certificate of Designation or the Amended and Restated Certificate that adversely affects the rights, preferences, privileges or voting powers of the Series B Preferred Stock or (b) authorize the issuance of any Senior Securities or Parity Securities. With respect to any matter on which the holders of the Series B Preferred Stock are entitled to vote, each share of Series B Preferred Stock shall be entitled to one vote on such matter.

        SECTION 6.    Dividends.    Notwithstanding anything to the contrary in the Amended and Restated Certificate, no dividends shall be declared or paid on the Series B Preferred Stock; provided, that holders of the Series B Preferred Stock shall be entitled to pro rata participation in any dividends paid on shares of the Class A Common Stock, on an as-converted basis at the then applicable Conversion Rate (defined below) whether or not the shares of Series B Preferred Stock are entitled to conversion.

        SECTION 7.    Transfer of Series B Preferred Stock.    Prior to the date of the special meeting of the Corporation's stockholders (the "Special Meeting") held to seek the approval, as required by The NASDAQ Capital Market ("NASDAQ"), of the issuance of the Conversion Shares in accordance with Section 8 (the "Stockholder Approval"), no holder of Series B Preferred Stock shall sell, contract to sell, pledge or otherwise dispose of any shares of Series B Preferred Stock without the prior written consent of the Corporation, except to an Affiliate of such holder or the Corporation or a subsidiary thereof. For purposes of this Certificate of Designation, (a) "Affiliate" shall mean, with respect to any person, any other person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the person in question; and (b) "control" means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a person, whether through ownership of voting securities, by contract or otherwise.

        SECTION 8.    Conversion.

a.

Upon the receipt by the Corporation of the Stockholder Approval (the "Conversion Date"), each share of Series B Preferred Stock shall automatically convert into two hundred and fifty (250) shares of Class A Common Stock (as adjusted to account for any subdivision (by stock split, subdivision, exchange, stock dividend, reclassification, recapitalization or otherwise) or combination (by reverse stock split, exchange, reclassification, recapitalization or otherwise) or similar reclassification or recapitalization of the outstanding shares of Class A Common Stock or into a greater or lesser number of shares of Class A Common Stock occurring after the date of this Certificate of Designation, the "Conversion Rate").



b.

As soon as possible after the Conversion Date (but in any event within three (3) business days thereof), the Corporation shall deliver to each holder of the Series B Preferred Stock: (i) the number of Conversion Shares issuable to such holder as a result of such conversion in book-entry form in the name of such holder or to a nominee or custodian designated by such holder, as applicable, and (ii) written notice from the Corporation or its transfer agent evidencing the issuance to such holder of the Conversion Shares.



c.

The issuance of the Conversion Shares upon conversion of the Series B Preferred Stock shall be made without charge to the holders of such Series B Preferred Stock for any issuance tax in respect thereof or other cost incurred by the Corporation in connection with such conversion and the related issuance of the Conversion Shares. Upon conversion of each share of Series B Preferred Stock, the Corporation shall take all such actions as are reasonably necessary in order to ensure that the Conversion Shares shall be validly issued, fully paid and

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non-assessable, free and clear of all taxes, liens, charges and encumbrances with respect to the issuance thereof.

d.

The Corporation shall not close its books against the transfer of the Series B Preferred Stock or of the Conversion Shares in any manner that interferes with the timely conversion of the Series B Preferred Stock.



e.

The Corporation shall at all times reserve and keep available out of its authorized but unissued shares of Class A Common Stock, solely for the purpose of issuance upon the conversion of the Series B Preferred Stock, a number of shares of Class A Common Stock equal to the number of Conversion Shares. The Corporation shall take all such actions as may be necessary to ensure that all of the Conversion Shares may be so issued without violation of any applicable law or governmental regulation or any requirements of the NASDAQ or other domestic securities exchange upon which shares of Class A Common Stock may then be listed (a "National Securities Exchange") (except for official notice of issuance, which shall be immediately delivered by the Corporation upon such issuance), including, without limitation, obtaining the Stockholder Approval prior to issuing any Conversion Shares. The Corporation shall not take any action that would cause the number of authorized but unissued shares of Class A Common Stock to be less than the number of such shares required to be reserved hereunder for issuance upon conversion of the Series B Preferred Stock.

        SECTION 9    Optional Redemption.    

a.

Beginning on the third anniversary of the date of this Certificate of Designation, the Corporation shall have the right, but not the obligation, to redeem all (but not less than all) of each holder's shares of Series B Preferred Stock for a redemption price per share (the "Redemption Price"), determined on an as-converted basis at the then applicable Conversion Rate whether or not the shares of Series B Preferred Stock are entitled to conversion, equal to the average of the last reported sale price for a share of Class A Common Stock on a National Securities Exchange for each of the last 10 consecutive trading days prior to the date of redemption (the "Redemption Date") or, if such shares are no longer traded on a National Securities Exchange, at the fair market value of the shares of Class A Common Stock, as determined in good faith by the Board.



b.

Notice shall be given not more than sixty (60) days or less than thirty (30) days prior to the Redemption Date to each holder of record of the shares of Series B Preferred Stock to be redeemed, by first class mail, postage prepaid, at such holder's address as the same appears on the stock records of the Corporation. Neither the failure to mail any such notice, nor any defect therein or in the mailing thereof, to any particular holder, shall affect the sufficiency of the notice or the validity of the proceedings for redemption with respect to the other holders. Any notice mailed in the manner herein provided shall be conclusively presumed to have been duly given on the date mailed, whether or not the holder receives the notice. Notwithstanding the foregoing, if shares of Series B Preferred Stock are issued in book-entry form through The Depository Trust Company or any other similar facility, notice of redemption may be given to the holders of the Series B Preferred Stock at such time and in any manner permitted by such facility. Each such notice shall state, in addition to any information the Corporation deems appropriate: (i) the Redemption Date; (ii) the Redemption Price; and (iii) the place or places where shares of Series B Preferred Stock are to be surrendered for redemption.



c.

In order to facilitate the redemption of the Series B Preferred Stock, the Board may cause the transfer books of the Corporation for the Series B Preferred Stock to be closed not more than thirty (30) days prior to the Redemption Date.

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d.

Unless the Corporation defaults in the payment of the Redemption Price, the shares of the Series B Preferred Stock to be redeemed shall from and after the close of business on the Redemption Date have only the right to receive payment of the Redemption Price. No interest shall accrue for the benefit of the holders of the Series B Preferred Stock to be redeemed on any sum set aside by the Corporation in connection with a redemption pursuant to this Section 9.



e.

As promptly as possible after the surrender of any shares of Series B Preferred Stock redeemed pursuant to this Section 9 (with appropriate endorsements and any transfer documents reasonably requested by the Corporation or any transfer agent designated by the Corporation), such shares shall be exchanged for the Redemption Price.



f.

Notwithstanding anything to the contrary contained herein, the Corporation's obligation to pay the Redemption Price shall be deemed fulfilled, and the applicable shares of Series B Preferred Stock shall be redeemed on the Redemption Date if, on or before the Redemption Date, the Corporation shall deposit with the transfer agent for the Series B Preferred Stock, cash in the amount of the Redemption Price in trust with irrevocable instructions that such cash be paid upon the tender of certificates representing the redeemed shares of Series B Preferred Stock. Subject to applicable escheat laws, any cash unclaimed at the end of six (6) years from the Redemption Date shall revert to the general funds of the Corporation and, upon demand, such bank or trust company shall be relieved of all responsibility in respect thereof and any holder of the Series B Preferred Stock shall look only to the general funds of the Corporation for payment of such cash. Any interest accrued on cash deposited pursuant to this Section 9(f) shall be paid from time to time to the Corporation for its own account.



g.

In the event that the Corporation shall default in the payment of the Redemption Price, the shares of Series B Preferred Stock so called for redemption shall thereafter be deemed to be outstanding and any holders thereof shall have all of the rights of a holder of the Series B Preferred Stock; provided, however, that the Corporation shall pay such Redemption Price, in whole or in part, as soon as it has funds legally available therefor. Anything to the contrary in this Section 9(g) notwithstanding, the Corporation shall not make any cash payment in respect of the Redemption Price at any time during which any amounts are outstanding under that certain Amended and Restated Credit Agreement, dated as of October 15, 2014, among Centennial Resource Production, LLC, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto, as amended to date (as may be further amended, supplemented, refinanced, extended or otherwise modified from time to time, the "Senior Debt"), to the extent that such cash payment is prohibited by the terms of the Senior Debt.

        SECTION 10.    Shares to be Retired.    All shares of Series B Preferred Stock converted into Class A Common Stock in accordance with Section 8 or redeemed by the Corporation in accordance with Section 9 shall be retired and cancelled and shall be restored to the status of authorized but unissued shares of Preferred Stock, without designation as to series.

        SECTION 11    Liquidation, Dissolution or Winding Up of the Corporation.    

a.

In the event of a voluntary or involuntary liquidation, dissolution or winding up of the Corporation (each a "Liquidation Event"), holders of the Series B Preferred Stock will first be entitled to receive the Liquidation Preference per share, to the date of payment before any distribution of assets is made to holders of any Junior Securities. If, in the event of a Liquidation Event, after payment of any amounts to be paid in respect of any Senior Securities, the Corporation's assets available for distribution are insufficient to fully pay the liquidation payments owing to the holders of the Series B Preferred Stock and the holders of any Parity Securities, the holders of the Series B Preferred Stock and such Parity Securities

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will share ratably in the distribution of the Corporation's assets in proportion to the full liquidating distributions to which they would otherwise have been respectively entitled. After the payment of the Liquidation Preference to the holders of the Series B Preferred Stock (and payment of any amount to be paid in respect of any Senior Securities and any Parity Securities), the remaining assets of the Corporation shall be distributed ratably to the holders of the Class A Common Stock and the Series B Preferred Stock on an as-converted basis at the then applicable Conversion Rate whether or not the shares of Series B Preferred Stock are entitled to conversion (and any other participating equity securities of the Corporation).

b.

For all purposes of this Certificate of Designation, the following events shall not constitute a Liquidation Event (i) the merger or consolidation of the Corporation with any other entity, including a merger or consolidation in which the holders of the Series B Preferred Stock receive cash, securities or property for their shares, the sale, lease or exchange of all or substantially all of the Corporation's assets for cash, securities or other property, (ii) the conversion of the Corporation into another legal entity or (iii) the sale of all or substantially all of the assets of the Corporation to an Affiliate in connection with a reorganization or liquidation.

        SECTION 12    Extraordinary Transactions Affecting the Corporation.    

a.

Prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of shares of Class A Common Stock are to receive cash, securities or property for their shares (a "Corporate Event"), the Corporation shall make appropriate provision to ensure that the holders of the Series B Preferred Stock receive in such Corporate Event a preferred security, issued by the entity surviving or resulting from such Corporate Event and containing provisions substantially equivalent to the provisions set forth in this Certificate of Designation without abridgement, including, without limitation, the same rights, preferences, privileges or voting powers that shares of the Series B Preferred Stock had immediately prior to such Corporate Event (the "Survivor Preferred Security"). The Conversion Rate in effect at the time of the effective date of such Corporate Event shall be proportionately adjusted so that the conversion of a share of Survivor Preferred Security after such time shall entitle the holder to the number of securities or amount of other assets which, if a share of Series B Preferred Stock had been converted into shares of Class A Common Stock immediately prior to such Corporate Event, such holder would have been entitled to receive immediately following such Corporate Event.



b.

If the Corporation desires to enter into a Corporate Event that will result in holders of shares of Class A Common Stock receiving exclusively cash consideration as a result thereof (a "Cash Event"), it shall use its commercially reasonable efforts to ensure that the parties to such Cash Event enter into documentation that provides that upon conversion of a share of Survivor Preferred Security, the holder thereof shall be entitled to receive, in lieu of such cash, a share or shares of Survivor Common Equity (as hereinafter defined). Each such Survivor Preferred Security shall initially (that is, immediately after the effective time of the Cash Event) entitle the holder to convert such Survivor Preferred Security into a number of shares of Survivor Common Equity that are equivalent in fair market value to the cash amount that would otherwise have been received by the holder had such holder's shares of Series B Preferred Stock been converted into shares of Class A Common Stock immediately prior to the Cash Event. As used herein, "Survivor Common Equity" means a share of the surviving entity that has (i) the right to vote generally in matters relating to the entity and (ii) the right to receive a pro rata portion of all of the equity remaining in the surviving entity upon liquidation after payment in full of (x) all indebtedness of the surviving entity and (y) amounts due in respect of all equity securities ranking more senior than such Survivor Common Equity.

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        SECTION 13    Severability.    In the event any provision of these terms for the Series B Preferred Stock is for any reason held by a court of competent jurisdiction to be invalid, illegal or unenforceable, such invalidity, illegality or unenforceability shall not affect any other provision hereof, and these terms for the Series B Preferred Stock shall be construed as if such invalid, illegal or unenforceable provision had never been contained herein.

[signature page follows]

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        IN WITNESS WHEREOF, the Corporation has caused this Certificate of Designation to be signed by its undersigned duly authorized officer this 28th day of December, 2016.

CENTENNIAL RESOURCE DEVELOPMENT, INC.
By:	/s/ MARK G. PAPA
	Name:	Mark G. Papa
	Title:	Chief Executive Officer

[Signature Page to Certificate of Designation]

Annex D

August 4, 2015

Mr. Ward Polzin
Centennial Resource Development, LLC
1401 Seventeenth Street, Suite 1000
Denver, Colorado 80202

Dear Mr. Polzin:

        In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2014, to the Centennial Resource Development, LLC (CRD) interest in certain oil and gas properties located in Reeves and Ward Counties, Texas. We completed our evaluation on or about February 6, 2015. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by CRD. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Centennial Resource Development, Inc.'s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

        We estimate the net reserves and future net revenue to the CRD interest in these properties, as of December 31, 2014, to be:

	Net Reserves						Future Net Revenue (M$)
Category	Oil (MBBL)		NGL (MBBL)		Gas (MMCF)		Total		Present Worth at 10%
Proved Developed Producing		7,989.5		763.6		11,910.3		534,287.2		297,584.5
Proved Developed Non-Producing		36.9		2.5		48.3		2,680.5		1,637.4
Proved Undeveloped		11,823.0		785.3		15,455.1		415,635.3		71,142.8
Total Proved		19,849.5		1,551.4		27,413.6		952,603.0		370,364.7

Totals may not add because of rounding.

        The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

        The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

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        Gross revenue is CRD's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for CRD's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

        Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2014. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.48 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $4.350 per MMBTU is adjusted for energy content, transportation fees, and market differentials. 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 $4.704 per MCF of gas.

        Operating costs used in this report are based on operating expense records of CRD. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses of CRD are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

        Capital costs used in this report were provided by CRD and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for well completions, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are CRD's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

        For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

        We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the CRD interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on CRD receiving its net revenue interest share of estimated future gross production.

        The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by CRD, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto

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could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

        For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

        The data used in our estimates were obtained from CRD, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Neil H. Little, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2011 and has over 9 years of prior industry experience. Mike K. Norton, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

		Sincerely,
		NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699
		By:	/s/ C.H. (SCOTT) REES III C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer
By:	/s/ NEIL H. LITTLE Neil H. Little, P.E. 117966 Vice President	By:	/s/ MIKE K. NORTON Mike K. Norton, P.G. 441 Senior Vice President
Date Signed: August 4, 2015		Date Signed: August 4, 2015
NHL:SMD

        Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

        The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

        (1)    Acquisition of properties.    Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

        (2)    Analogous reservoir.    Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);



(ii)

Same environment of deposition;



(iii)

Similar geological structure; and



(iv)

Same drive mechanism.

        Instruction to paragraph (a)(2):    Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

        (3)    Bitumen.    Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

        (4)    Condensate.    Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

        (5)    Deterministic estimate.    The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

        (6)    Developed oil and gas reserves.    Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and



(ii)

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves—Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves—Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

        (7)    Development costs.    Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)

Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.



(ii)

Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.



(iii)

Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.



(iv)

Provide improved recovery systems.

        (8)    Development project.    A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

        (9)    Development well.    A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

        (10)    Economically producible.    The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

        (11)    Estimated ultimate recovery (EUR).    Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

        (12)    Exploration costs.    Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

D-5

(i)

Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.



(ii)

Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.



(iii)

Dry hole contributions and bottom hole contributions.



(iv)

Costs of drilling and equipping exploratory wells.



(v)

Costs of drilling exploratory-type stratigraphic test wells.

        (13)    Exploratory well.    An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

        (14)    Extension well.    An extension well is a well drilled to extend the limits of a known reservoir.

        (15)    Field.    An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

        (16)    Oil and gas producing activities.

(i)

Oil and gas producing activities include:



(A)

The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;



(B)

The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;



(C)

The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:



(1)

Lifting the oil and gas to the surface; and



(2)

Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and



(D)

Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

        Instruction 1 to paragraph (a)(16)(i):    The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual

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physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.

The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and



b.

In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

        Instruction 2 to paragraph (a)(16)(i):    For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)

Oil and gas producing activities do not include:



(A)

Transporting, refining, or marketing oil and gas;



(B)

Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;



(C)

Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or



(D)

Production of geothermal steam.

        (17)    Possible reserves.    Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.



(ii)

Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.



(iii)

Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.



(iv)

The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.



(v)

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

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(vi)

Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

        (18)    Probable reserves.    Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.



(ii)

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.



(iii)

Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.



(iv)

See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

        (19)    Probabilistic estimate.    The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

        (20)    Production costs.

(i)

Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:



(A)

Costs of labor to operate the wells and related equipment and facilities.



(B)

Repairs and maintenance.



(C)

Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.



(D)

Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. (E) Severance taxes.



(ii)

Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration,

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and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

        (21)    Proved area.The part of a property to which proved reserves have been specifically attributed.

        (22)    Proved oil and gas reserves.Proved oil and gas reserves are those quantities of oil and 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)

The area of the reservoir considered as proved includes:



(A)

The area identified by drilling and limited by fluid contacts, if any, and



(B)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.



(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.



(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.



(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:



(A)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and



(B)

The project has been approved for development by all necessary parties and entities, including governmental entities.



(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

        (23)    Proved properties.Properties with proved reserves.

        (24)    Reasonable certainty.If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be

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at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

        (25)    Reliable technology.Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

        (26)    Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

        Note to paragraph (a)(26):    Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a.

Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b.

Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a.

Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b.

Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c.

Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

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d.

Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e.

Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f.

Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

        (27)    Reservoir.    A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

        (28)    Resources.    Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

        (29)    Service well.    A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

        (30)    Stratigraphic test well.    A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

        (31)    Undeveloped oil and gas reserves.    Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.



(ii)

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects—such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations—by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

•

The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

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•

The company's historical record at completing development of comparable long-term projects;

•

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

•

The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

•

The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

        (32)    Unproved properties.    Properties with no proved reserves.

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May 12, 2016

Mr. Ward Polzin
Centennial Resource Development, LLC
1401 Seventeenth Street, Suite 1000
Denver, Colorado 80202

Dear Mr. Polzin:

        In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2015, to the Centennial Resource Production, LLC (CRP) interest in certain oil and gas properties located in Reeves and Ward Counties, Texas. CRP is a subsidiary of Centennial Resource Development, LLC (CRD). We completed our evaluation on or about March 3, 2016. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by CRP. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for CRP's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

        We estimate the net reserves and future net revenue to the CRP interest in these properties, as of December 31, 2015, to be:

	Net Reserves						Future Net Revenue (M$)
Category	Oil (MBBL)		NGL (MBBL)		Gas (MMCF)		Total		Present Worth at 10%
Proved Developed Producing		9,346.9		1,603.1		12,711.1		216,269.6		141,416.4
Proved Undeveloped		13,852.2		2,248.2		19,730.5		135,797.3		4,057.0
Total Proved		23,199.0		3,851.4		32,441.6		352,066.9		145,473.4

Totals may not add because of rounding.

        The oil volumes shown include crude oil only. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

        The estimates shown in this report are for proved developed producing and proved undeveloped reserves. Our study indicates that there are no proved developed non-producing reserves for these properties at this time. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

        Gross revenue is CRP's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for CRP's share of production taxes, ad valorem

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taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

        Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2015. For oil and NGL volumes, the average West Texas Intermediate posted price of $46.79 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.587 per MMBTU is adjusted for energy content, transportation fees, and market differentials. 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 $1.707 per MCF of gas.

        Operating costs used in this report are based on operating expense records of CRP. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Headquarters general and administrative overhead expenses of CRP are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

        Capital costs used in this report were provided by CRP and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for new development wells and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are CRP's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

        For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

        We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the CRP interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on CRP receiving its net revenue interest share of estimated future gross production.

        The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by CRP, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of

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supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

        For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

        The data used in our estimates were obtained from CRP, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Neil H. Little, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2011 and has over 9 years of prior industry experience. Mike K. Norton, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

		Sincerely,
		NETHERLAND, SEWELL & ASSOCIATES, INC.
		Texas Registered Engineering Firm F-2699
		By:	/s/ C.H. (SCOTT) REES III C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer
By:	/s/ NEIL H. LITTLE Neil H. Little, P.E. 117966 Vice President	By:	/s/ MIKE K. NORTON Mike K. Norton, P.G. 441 Senior Vice President

Date Signed: May 12, 2016 Date Signed: May 12, 2016

        Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

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DEFINITIONS OF OIL AND GAS RESERVES

        Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

        The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

        (1)    Acquisition of properties.    Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

        (2)    Analogous reservoir.    Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);



(ii)

Same environment of deposition;



(iii)

Similar geological structure; and



(iv)

Same drive mechanism.

        Instruction to paragraph (a)(2):    Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

        (3)    Bitumen.    Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

        (4)    Condensate.    Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

        (5)    Deterministic estimate.    The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

        (6)    Developed oil and gas reserves.    Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and



(ii)

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves—Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves—Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

        (7)    Development costs.    Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)

Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.



(ii)

Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.



(iii)

Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.



(iv)

Provide improved recovery systems.

        (8)    Development project.    A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

        (9)    Development well.    A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

        (10)    Economically producible.    The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

        (11)    Estimated ultimate recovery (EUR).    Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

        (12)    Exploration costs.    Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

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(i)

Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.



(ii)

Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.



(iii)

Dry hole contributions and bottom hole contributions.



(iv)

Costs of drilling and equipping exploratory wells.



(v)

Costs of drilling exploratory-type stratigraphic test wells.

        (13)    Exploratory well.    An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

        (14)    Extension well.    An extension well is a well drilled to extend the limits of a known reservoir.

        (15)    Field.    An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

        (16)    Oil and gas producing activities.

(i)

Oil and gas producing activities include:



(A)

The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;



(B)

The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;



(C)

The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:



(1)

Lifting the oil and gas to the surface; and



(2)

Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and



(D)

Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

        Instruction 1 to paragraph (a)(16)(i):    The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual

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physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.

The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and



b.

In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

        Instruction 2 to paragraph (a)(16)(i):    For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)

Oil and gas producing activities do not include:



(A)

Transporting, refining, or marketing oil and gas;



(B)

Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;



(C)

Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or



(D)

Production of geothermal steam.

        (17)    Possible reserves.    Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.



(ii)

Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.



(iii)

Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.



(iv)

The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.



(v)

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

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(vi)

Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

        (18)    Probable reserves.    Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.



(ii)

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.



(iii)

Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.



(iv)

See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

        (19)    Probabilistic estimate.    The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

        (20)    Production costs.

(i)

Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:



(A)

Costs of labor to operate the wells and related equipment and facilities.



(B)

Repairs and maintenance.



(C)

Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.



(D)

Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.



(E)

Severance taxes.



(ii)

Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration,

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and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

        (21)    Proved area.    The part of a property to which proved reserves have been specifically attributed.

        (22)    Proved oil and gas reserves.    Proved oil and gas reserves are those quantities of oil and 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)

The area of the reservoir considered as proved includes:



(A)

The area identified by drilling and limited by fluid contacts, if any, and



(B)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.



(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.



(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.



(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:



(A)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and



(B)

The project has been approved for development by all necessary parties and entities, including governmental entities.



(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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        (23)    Proved properties.    Properties with proved reserves.

        (24)    Reasonable certainty.    If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

        (25)    Reliable technology.    Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

        (26)    Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

        Note to paragraph (a)(26):    Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a.

Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)



b.

Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a.

Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b.

Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c.

Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future

D-22

pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

d.

Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e.

Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f.

Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

        (27)    Reservoir.    A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

        (28)    Resources.    Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

        (29)    Service well.    A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

        (30)    Stratigraphic test well.    A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

        (31)    Undeveloped oil and gas reserves.    Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.



(ii)

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects—such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations—by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

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Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

•

The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

•

The company's historical record at completing development of comparable long-term projects;

•

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

•

The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

•

The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

        (32)    Unproved properties.    Properties with no proved reserves.

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ANNEX E: GLOSSARY OF OIL AND NATURAL GAS TERMS

        The following are abbreviations and definitions of certain terms used in this proxy statement, which are commonly used in the oil and natural gas industry:

        3-D seismic.    Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

        Analogous reservoir.    Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an analogous reservoir refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar geological structure; and (iv) same drive mechanism. For a complete definition of analogous reservoir, refer to the SEC's Regulation S-X, Rule 4-10(a)(2).

        Basin.    A large natural depression on the earth's surface in which sediments generally brought by water accumulate.

        Bbl.    One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.

        Bcf.    One billion cubic feet of natural gas.

        Boe.    One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

        Boe/d.    One Boe per day.

        British thermal unit or Btu.    The quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

        Completion.    Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

        Condensate.    A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

        Delineation.    The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

        Developed acreage.    The number of acres that are allocated or assignable to productive wells or wells capable of production.

        Development costs.    Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. For a complete definition of development costs refer to the SEC's Regulation S-X, Rule 4-10(a)(7).

        Development project.    The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental

E-1

development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

        Development well.    A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

        Differential.    An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

        Downspacing.    Additional wells drilled between known producing wells to better develop the reservoir.

        Dry well.    A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

        Economically producible.    The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC's Regulation S-X, Rule 4-10(a)(10).

        Estimated ultimate recovery or EUR.    The sum of reserves remaining as of a given date and cumulative production as of that date.

        Exploration costs.    Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. For a complete definition of exploration costs, refer to the SEC's Regulation S-X, Rule 4-10(a)(12).

        Exploratory well.    A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

        Field.    An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC's Regulation S-X, Rule 4-10(a)(15).

        Formation.    A layer of rock which has distinct characteristics that differs from nearby rock.

        Gross acres or gross wells.    The total acres or wells, as the case may be, in which a working interest is owned.

        Held by production.    Acreage covered by a mineral lease that perpetuates a company's right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

        Horizontal drilling.    A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

        MBbl.    One thousand barrels of crude oil, condensate or NGLs.

        MBoe.    One thousand Boe.

        Mcf.    One thousand cubic feet of natural gas.

        Mcf/d.    One Mcf per day.

        MMBbl.    One million barrels of crude oil, condensate or NGLs.

E-2

        MMBoe.    One million Boe.

        MMBtu.    One million British thermal units.

        MMcf.    One million cubic feet of natural gas.

        Net acres.    The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

        Net production.    Production that is owned less royalties and production due to others.

        Net revenue interest.    A working interest owner's gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

        NGLs.    Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

        NYMEX.    The New York Mercantile Exchange.

        Offset operator.    Any entity that has an active lease on an adjoining property for oil, natural gas or NGLs purposes.

        Operator.    The individual or company responsible for the development and/or production of an oil or natural gas well or lease.

        Play.    A geographic area with hydrocarbon potential.

        Present value of future net revenues or PV-10.    The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

        Production costs.    Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC's Regulation S-X, Rule 4-10(a)(20).

        Productive well.    A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

        Prospect.    A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

        Proved developed reserves.    Reserves that can be expected to be recovered through (i) existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

        Proved properties.    Properties with proved reserves.

        Proved reserves.    Those quantities of oil, natural gas and NGLs, 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

E-3

operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC's Regulation S-X, Rule 4-10(a)(22).

        Proved undeveloped reserves or PUDs.    Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

        Realized price.    The cash market price less all expected quality, transportation and demand adjustments.

        Reasonable certainty.    A high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC's Regulation S-X, Rule 4-10(a)(24).

        Recompletion.    The completion for production of an existing wellbore in another formation from that which the well has been previously completed

        Reliable technology.    Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

        Reserves.    Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

        Reservoir.    A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

        Resources.    Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

        Royalty.    An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

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        Service well.    A well drilled or completed for the purpose of supporting production in an existing field.

        Spacing.    The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g.,  40-acre spacing, and is often established by regulatory agencies.

        Spot market price.    The cash market price without reduction for expected quality, transportation and demand adjustments.

        Spud.    Commenced drilling operations on an identified location.

        Standardized measure.    Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

        Stratigraphic test well.    A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

        Success rate.    The percentage of wells drilled which produce hydrocarbons in commercial quantities.

        Undeveloped acreage.    Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

        Unit.    The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

        Unproved properties.    Properties with no proved reserves.

        Wellbore.    The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

        Working interest.    The right granted to the lessee of a property to develop and produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

        Workover.    Operations on a producing well to restore or increase production.

        WTI.    West Texas Intermediate.

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