Amendment No. 1 to
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

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

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

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

Approximate date of commencement of proposed sale to the public:
From time to time after the effective date of this Registration Statement.

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

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

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

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

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

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

The information contained in this prospectus is not complete and may be changed. No securities may be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

16,666,643 Shares of Class A Common Stock Issuable upon Exercise of
Outstanding Public Warrants 121,005,000 Shares of Class A Common Stock

This prospectus relates to the issuance by Centennial Resource Developmental, Inc. (the "Company," "we," "our" or "us") of 16,666,643 shares of our Class A Common Stock, par value $0.0001 per share (the "Class A Common Stock"), upon the exercise of warrants (the "Public Warrants") originally sold as part of units, consisting of one share of Class A Common Stock and one-third of one Public Warrant (the "Units"), in our initial public offering (our "IPO"). Each Public Warrant entitles the holder to purchase one share of Class A Common Stock at an exercise price of $11.50 per share. We will receive the proceeds from the exercise of the Public Warrants, but not from the sale of the underlying shares of Class A Common Stock.

This prospectus also relates to the resale of 121,005,000 shares of Class A Common Stock by the selling stockholders named in this prospectus or their permitted transferees. The shares of Class A Common Stock being offered by the selling stockholders consist of (i) 20,000,000 shares of Class A Common Stock that have been or may be issued from time to time to certain members of Centennial Resource Production, LLC, a Delaware limited liability company ("CRP"), who own units representing common membership interest in CRP (the "CRP Common Units"), upon the redemption or exchange by such members of CRP Common Units for shares of Class A Common Stock (the "Centennial Holder Shares") pursuant to the limited liability company agreement of CRP and (ii) 101,005,000 shares of Class A Common Stock that we sold in private placements that closed simultaneously with the consummation of our initial business combination (the "Private Placement Shares").

The selling stockholders may offer, sell or distribute all or a portion of their shares of Class A Common Stock publicly or through private transactions at prevailing market prices or at negotiated prices. We will not receive any of the proceeds from the sale of the shares of Class A Common Stock owned by the selling stockholders. We will bear all costs, expenses and fees in connection with the registration of these shares of Class A Common Stock, including with regard to compliance with state securities or "blue sky" laws. The selling stockholders will bear all commissions and discounts, if any, attributable to their sale of shares of Class A Common Stock. See "Plan of Distribution" beginning on page 132 of this prospectus.

The Class A Common Stock and Public Warrants are quoted on The NASDAQ Capital Market ("NASDAQ") under the symbols "CDEV" and "CDEVW," respectively. On November 15, 2016, the closing prices of our Class A Common Stock and Public Warrants were $14.63 and $4.61, respectively. As of November 15, 2016, we had 164,349,079 shares of Class A Common Stock and 16,666,643 Public Warrants issued and outstanding.

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

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

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

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

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

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

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

PROSPECTUS SUMMARY

This summary highlights certain information appearing elsewhere in this prospectus. For a more complete understanding of this offering, you should read the entire prospectus carefully, including the risk factors and the financial statements.

Our Company

Corporate History

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

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

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

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

Business Overview

Following the Business Combination, our only significant asset is our ownership of an approximate 89% membership interest in CRP. We are an independent oil and natural gas company focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, and our properties consist of large, contiguous acreage blocks in Reeves, Ward and Pecos counties in West Texas.

As of September 30, 2016, our portfolio included 63 operated producing horizontal wells. The horizontal wells span an area approximately 45 miles long by 20 miles wide where we have established

commercial production in five distinct zones: the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C. As a result, we have broadly appraised our acreage across various geographic areas and stratigraphic zones, which we expect will allow us to efficiently develop our drilling inventory with a focus on maximizing returns to our stockholders. In addition, we believe our acreage may be prospective for the 2nd and 3rd Bone Spring shales and Avalon Shale, where other operators have experienced drilling success near our acreage.

We have leased or acquired approximately 42,300 net acres, approximately 80% of which we operate, as of September 30, 2016. Our acreage is predominantly located in the southern portion of the Delaware Basin, where production and reserves typically contain a higher percentage of oil and natural gas liquids and a correspondingly lower percentage of natural gas compared to the northern portion of the Delaware Basin. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, we added one horizontal rig in June 2016, a second horizontal rig in September 2016 and a third horizontal rig in October 2016. During 2015, we operated, on average, one rig and placed 13 horizontal wells on production. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus on optimizing completions, reducing drilling times and reducing costs.

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

Organizational Structure

The following diagram illustrates the current ownership structure of the Company.

(1): CRD also owns one share of our Series A Preferred Stock, par value $0.0001 per share (the "Series A Preferred Stock"), which does not have any voting rights (other than the right to nominate and elect one director to our board of directors) or rights with respect to dividends but is entitled to preferred distributions in liquidation in the amount of $0.0001 per share.
(2): The economic and voting interests set forth above do not account for the outstanding Public Warrants and Private Placement Warrants.

Additional Information

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

Our Emerging Growth Company Status

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

•: the presentation of only two years of audited financial statements and only two years of related Management's Discussion and Analysis of Financial Condition and Results of Operations;
•: deferral of the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting;
•: exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;
•: exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and
•: reduced disclosure about executive compensation arrangements.

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

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

The Offering

We are registering (i) the issuance by us of 16,666,643 shares of Class A Common Stock underlying the Public Warrants and (ii) the resale of 121,005,000 shares of Class A Common Stock by the selling stockholders named in this prospectus, or their permitted transferees.

Issuance of Class A Common Stock Underlying the Public Warrants


Shares of Class A Common Stock to be Issued upon Exercise of the Public Warrants		16,666,643 shares of Class A Common Stock.
Shares of Class A Common Stock Outstanding Prior to Exercise of the Public Warrants(1)		164,349,079 shares of Class A Common Stock, as of November 15, 2016.
Shares of Class A Common Stock to be Outstanding Assuming Exercise of the Public Warrants(1)		181,015,722 shares of Class A Common Stock.
Terms of the Public Warrants		Each whole Public Warrant entitles the holder to purchase one whole share of Class A Common Stock for $11.50 per share, at any time commencing on February 29, 2017, which is 12 months following the closing of our IPO. The Public Warrants will expire at 5:00 p.m., New York time, on October 11, 2021 (which is five years after the completion of the Business Combination) or earlier upon redemption or liquidation.
Use of Proceeds		We expect to receive $191,666,395 in net proceeds assuming the exercise of all of our Public Warrants at the exercise price of $11.50 per share. We intend to use these net proceeds for general corporate purposes.
Trading Market and Ticker Symbol		Our Public Warrants are listed on NASDAQ under the symbol "CDEVW."
Resale of Class A Common Stock by Selling Stockholders
Shares Offered by the Selling Stockholders		We are registering 121,005,000 shares of Class A Common Stock to be offered by the selling stockholders named herein, which includes 20,000,000 Centennial Holder Shares and 101,005,000 Private Placement Shares.
Terms of the Offering		The selling stockholders will determine when and how they will dispose of the shares of Class A Common Stock registered under this prospectus for resale.


Shares Outstanding Prior to This Offering(1)(2)		As of November 15, 2016, 164,349,079 shares of Class A Common Stock, 19,155,921 shares of Class C Common Stock and 1 share of Series A Preferred Stock are issued and outstanding.
Shares Outstanding After This Offering(1)(2)		164,349,079 shares of Class A Common Stock and 1 share of Series A Preferred Stock.
Use of Proceeds		We will not receive any of the proceeds from the sale of shares of Class A Common Stock by the selling stockholders.
Trading Market and Ticker Symbol		Our Class A Common Stock is listed on NASDAQ under the symbol "CDEV."

(1): The number of shares of Class A Common Stock does not include (i) the 16,500,000 shares of Class A Common Stock available for future issuance under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan or (ii) the 8,000,000 shares of Class A Common Stock issuable upon exercise of the Private Placement Warrants.
(2): The number of shares of Class A Common Stock does not include the 16,666,643 shares of Class A Common Stock issuable upon exercise of the Public Warrants.

For additional information concerning the offering, see "Plan of Distribution" beginning on page 132.

Risk Factors

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

Summary Historical Reserve and Operating Data

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

The reserve estimates attributable to our properties as of December 31, 2015 presented in the table below are based on a reserve report prepared by Netherland, Sewell & Associates, Inc., our independent petroleum engineer. A copy of the reserve report is included as Exhibit 99.2 to the registration statement of which this prospectus forms a part. All of these reserve estimates were prepared in accordance with the SEC's rules regarding oil and natural gas reserve reporting that are currently in effect. The following tables also contain summary unaudited information regarding production and sales of oil, natural gas and NGLs with respect to such properties.

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

	As of December 31, 2015(1)

Proved Reserves:
Oil (MBbls)		23,199
Natural gas (MMcf)		32,442
NGLs (MBbls)		3,851

Total proved reserves (MBoe)		32,457
Proved Developed Reserves:
Oil (MBbls)		9,347
Natural gas (MMcf)		12,711
NGLs (MBbls)		1,603

Total proved developed reserves (MBoe)		13,068
Proved developed reserves as a percentage of total proved reserves		40	%
Proved Undeveloped Reserves:
Oil (MBbls)		13,852
Natural gas (MMcf)		19,731
NGLs (MBbls)		2,248

Total proved undeveloped reserves (MBoe)		19,389
Oil and Natural Gas Prices:
Oil—WTI posted price per Bbl	$	46.79
Natural gas—Henry Hub spot price per MMBtu	$	2.59

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

price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $41.85 per barrel of oil, $13.94 per barrel of NGL and $1.71 per Mcf of gas as of December 31, 2015.

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

Production and Operating Data:
Net Production Volumes(1):
Oil (MBbls)		1,520		1,830
Natural gas (MMcf)		2,551		3,058
NGLs (MBbls)		242		331

Total (MBoe)		2,187		2,671



Average net daily production (Boe/d)		7,982		7,317
Average Sales Prices:
Oil (per Bbl) (excluding impact of cash settled derivatives)	$	37.48	$	42.43
Oil (per Bbl) (after impact of cash settled derivatives)		48.42		61.61
Natural gas (per Mcf) (excluding impact of cash settled derivatives)		2.24		2.60
Natural gas (per Mcf) (after impact of cash settled derivatives)		2.24		3.04
NGLs (per Bbl)		12.80		14.66

Total (per Boe) (excluding impact of cash settled derivatives)		30.08		33.87
Total (per Boe) (after impact of cash settled derivatives)		37.68		47.51
Average Unit Costs per Boe:
Lease operating expenses	$	4.71	$	7.93
Severance and ad valorem taxes		1.61		1.88
Transportation, processing, gathering and other operating expenses		2.00		2.15
Depreciation, depletion, amortization, and accretion of asset retirement obligations		27.86		33.73
Abandonment expense and impairment of unproved properties		1.16		2.85
Exploration		—		0.03
Contract termination and rig stacking		—		0.89
General and administrative expenses.		4.87		5.32

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

Investing in our securities involves a high degree of risk. You should consider carefully the risks and uncertainties described below, together with all of the other information in this prospectus, including our consolidated financial statements and related notes, before deciding whether to purchase any of our securities. Any of these risks may have a material adverse effect on our business, financial condition, results of operations and cash flows and our prospects could be harmed. In that event, the price of our securities could decline and you could lose part or all of your investment.

Our only significant asset is ownership of an approximate 89% membership interest in CRP and such ownership 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.

We have no direct operations and no significant assets other than the ownership of an approximate 89% 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:

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 thus far in 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 thus far 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.

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

materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.

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

The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures related to development and acquisition projects. We have funded, and we expect that we will continue to fund, our capital expenditures with cash generated by operations and borrowings under CRP's revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

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

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

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:

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:

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.

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

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

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

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

The restrictions in CRP's credit agreement may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants impose on us.

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

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

CRP's revolving credit facility limits the amounts CRP can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually on April 1 and October 1. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the loan. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under CRP's revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. In connection with the Business Combination, the borrowing base was increased from $140 million to $200 million to accommodate an increased borrowing base. The next scheduled borrowing base redetermination is expected in April 2017.

In the future, we may not be able to access adequate funding under CRP's revolving credit facility (or a replacement facility) as a result of a decrease in the borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender's portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, CRP could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service CRP's indebtedness.

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

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

of 448 MBbls of our projected oil production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

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

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

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

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

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

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected, and production declines may be greater than our estimates and may be more rapid and irregular when

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

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of December 31, 2015 and related standardized measure were calculated under rules of the SEC using twelve-month trailing average benchmark prices of $46.79 per barrel of oil (WTI) and $2.59 per MMBtu (Henry Hub spot), which, for certain periods in 2016, were substantially higher than the available spot prices. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.

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.

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

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

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

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

locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

As of September 30, 2016, we had identified 1,388 horizontal drilling locations on our acreage based on approximately 880-foot spacing with five to six wells per 640-acre section in the Wolfcamp zones and approximately 1,320-foot spacing with four wells per 640-acre section in the 3rd Bone Spring Sandstone, in each case, consisting of laterals ranging from 4,500 feet up to 9,500 feet. As a result of the limitations described above, we may be unable to drill many of our identified locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See "—Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves." Any drilling activities we are able to conduct on these locations may not be successful or enable us to add additional proved reserves to our overall 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. 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.

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 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 delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

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

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

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

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

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

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

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

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

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

In the future we may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we will be able to identify attractive acquisition

opportunities. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.

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

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

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 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 was signed in April 2016, and is expected to enter into force in November 2016. The United States is one of over 70 nations having ratified or otherwise consented to be bound by the agreement. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our 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 June 2015, the EPA released its draft 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. The draft report is expected to be finalized after a public comment period and a formal review by the EPA's Science Advisory Board. 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 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 of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past three years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

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

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

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

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

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.

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

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 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.

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

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

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

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

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

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

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

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

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.

Fluctuations in the price of our securities could contribute to the loss of all or part of your investment. Prior to the completion 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.

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 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 the majority of our outstanding voting common stock.

Riverstone and its affiliates, including our Sponsor, beneficially own approximately 50.9% 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, and will be able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company.

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 Charter (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 a "controlled company" within the meaning of the NASDAQ Listing Rules and qualify for exemptions from certain corporate governance requirements.

Riverstone and its affiliates, including our Sponsor, control a majority of the combined voting power of all classes of our outstanding voting stock. As a result, we are a controlled company within the meaning of the NASDAQ corporate governance standards. Under the NASDAQ rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and we have elected not to comply with certain NASDAQ corporate governance requirements, including the requirements that:

These requirements will not apply to us as long as we remain a controlled company. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NASDAQ. See "Management—Status as a Controlled Company."

There is no guarantee that the Public Warrants will be in the money at a time when they are exercisable, and they may expire worthless and the terms of our Public Warrants may be amended.

The exercise price for our Public Warrants is $11.50 per share. There is no guarantee that the Public Warrants will be in the money at a time when they are exercisable, and as such, the Public Warrants may expire worthless.

In addition, the warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and us provides that the terms of the Public Warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by the holders of at least 50% of the then outstanding Public Warrants to make any change that adversely affects the interests of the registered holders. Accordingly, we may amend the terms of

the Public Warrants in a manner adverse to a holder if holders of at least 50% of the then outstanding Public Warrants approve of such amendment. Although our ability to amend the terms of the Public Warrants with the consent of at least 50% of the then outstanding Public Warrants is unlimited, examples of such amendments could be amendments to, among other things, increase the exercise price of the Public Warrants, shorten the exercise period or decrease the number of shares of our Class A Common Stock purchasable upon exercise of a Public Warrant.

We may redeem the Public Warrants prior to their exercise at a time that is disadvantageous to holders, thereby making their Public Warrants worthless.

We have the ability to redeem the outstanding Public Warrants at any time after they become exercisable and prior to their expiration at a price of $0.01 per warrant, provided that (i) the last reported sale price of our Class A Common Stock equals or exceeds $18.00 per share for any 20 trading days within the 30 trading-day period ending on the third business day before we send the notice of such redemption and (ii) on the date we give notice of redemption and during the entire period thereafter until the time the Public Warrants are redeemed, there is an effective registration statement under the Securities Act covering the shares of our Class A Common Stock issuable upon exercise of the Public Warrants and a current prospectus relating to them is available. Redemption of the outstanding Public Warrants could force holders of Public Warrants:

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:

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

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 and Public Warrants.

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 or Public Warrants 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 or Public Warrants 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.

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

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

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

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

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

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

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

We will receive the proceeds from the exercise of Public Warrants, but not from the sale of the underlying shares of Class A Common Stock. Assuming the exercise of all of the Public Warrants at an exercise price of $11.50 per share, we expect to receive $191,666,395.We intend to use any proceeds for general corporate purposes.

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

The offering price of the shares of Class A Common Stock underlying the Public Warrants offered hereby is determined by reference to the exercise price of the Public Warrants of $11.50 per share. The Public Warrants are listed on NASDAQ under the symbol "CDEVW."

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

Our Class A Common Stock and Public Warrants are currently listed on NASDAQ under the symbols "CDEV" and "CDEVW," respectively. Through October 11, 2016, our Class A Common Stock, Public Warrants and Units were listed under the symbols "SRAQ," "SRAQW," and "SRAQU," respectively. Upon the consummation of the Business Combination, we separated our Units, which were sold in our IPO, into their component securities of one share of Class A Common Stock and one-third of one Public Warrant, and the Units ceased public trading.

The following table sets forth for the periods indicated, the reported high and low bid quotations per share for our Class A Common Stock.

On November 15, 2016, the closing price of our Class A Common Stock and Public Warrants was $14.63 and $4.61, respectively. As of November 15, 2016, there were 164,349,079 shares of Class A Common Stock outstanding, held of record by 23 holders. In addition, 16,666,643 shares of Class A Common Stock are issuable upon exercise of the 16,666,643 Public Warrants, held of record by 2 holders. The number of record holders of our Class A Common Stock and Public Warrants does not include DTC participants or beneficial owners holding shares or Public Warrants through nominee names.

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

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

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

CRP's historical results are not necessarily indicative of future operating results. The selected consolidated and combined financial information should be read in conjunction with "Capitalization," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical consolidated and combined financial statements of CRP and accompanying notes included elsewhere in this prospectus.

	Nine Months Ended September 30,						Year Ended December 31,

	2016			2015			2015			2014			2013
	(Unaudited)
	(in thousands)
Statement of Operations Data:
Revenues:
Oil sales	$	56,975		$	59,068		$	77,643		$	114,955		$	65,863
Natural gas sales		5,717			6,082			7,965			9,670			3,024
NGL sales		3,097			3,590			4,852			7,200			3,087

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

Operating expenses:
Lease operating expenses		10,295			17,317			21,173			17,690			19,106
Severance and ad valorem taxes		3,523			3,833			5,021			6,875			4,153
Transportation, processing, gathering and other operating expenses		4,375			4,352			5,732			4,772			1,291
Depreciation, depletion, amortization and accretion of asset retirement obligations		60,939			64,003			90,084			69,110			29,285
Abandonment expense and impairment of unproved properties		2,546			3,851			7,619			20,025			8,561
Exploration		—			—			84			—			—
Contract termination and rig stacking		—			2,388			2,387			—			—
General and administrative expenses		10,655			8,538			14,206			31,694			16,842

Total operating expenses		92,333			104,282			146,306			150,166			79,238

Loss (gain) on sale of oil and natural gas properties		(11	)		(2,688	)		(2,439	)		2,096			(16,756	)

Total operating (loss) income		(26,533	)		(32,854	)		(53,407	)		(20,437	)		9,492

Other income (expense):
Interest expense		(5,422	)		(4,743	)		(6,266	)		(2,475	)		(513	)
(Loss) gain on derivatives instruments		(4,184	)		12,320			20,756			41,943			(4,410	)
Other income		6			(5	)		20			281			122

Total other (expense) income		(9,600	)		7,572			14,510			39,749			(4,801	)

(Loss) income before taxes		(36,133	)		(25,282	)		(38,897	)		19,312			4,691
Income tax benefit (expense)(2)		406			—			572			(1,524	)		(1,079	)

Net (loss) income		(35,727	)		(25,282	)		(38,325	)		17,788			3,612
Less: Net loss attributable to noncontrolling interest		—			—			—			(2	)		(6	)

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



Cash Flow Data:
Net cash provided by operating activities	$	51,511		$	48,474		$	68,882		$	97,248		$	13,416
Net cash used in investing activities		(100,975	)		(171,316	)		(198,635	)		(163,380	)		(136,517	)
Net cash provided by financing activities		48,106			110,219			118,504			36,966			118,742
Other Financial Data:
Adjusted EBITDAX(1)	$	53,570		$	60,667		$	82,279		$	88,108		$	18,059

			December 31,

	September 30, 2016		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

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").

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

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

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

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

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

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

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

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

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

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

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

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

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

We have leased or acquired approximately 42,300 net acres, approximately 80% of which we operate, as of September 30, 2016. Our acreage is predominantly located in the southern portion of the Delaware Basin, where production and reserves typically contain a higher percentage of oil and natural gas liquids and a correspondingly lower percentage of natural gas compared to the northern portion of the Delaware Basin. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, we added one horizontal rig in June 2016, a second horizontal rig in September 2016 and a third horizontal rig in October 2016. During 2015, we operated, on average, one rig and placed 13 horizontal wells on production. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus on reducing drilling times, optimizing completions and reducing costs.

The Permian Basin is an attractive operating area due to its extensive original oil-in-place, favorable operating environment, multiple horizontal zones, high oil and liquids-rich natural gas content, well-developed network of oilfield service providers, long-lived reserves with relatively consistent reservoir quality and historically high drilling success rates. According to the U.S. Energy Information Administration (the "EIA"), the Permian Basin is the most prolific oil producing area in the United States, accounting for 23% and 20% of total U.S. crude oil production during the twelve-month periods ended April 30, 2016 and April 30, 2015, respectively.

Over the past decade, the Delaware Basin has experienced significant horizontal drilling. According to Baker Hughes, three of the top six Permian Basin counties by horizontal rig count are located in the Delaware Basin. Reeves County, where the majority of our acreage is located, had the second most horizontal rigs of any U.S. county as of June 17, 2016, with 21 rigs as of such date. As a result of this horizontal drilling, the Delaware Basin is the only region in the United States that has

experienced sustained fourth quarter-to-fourth quarter production growth rates greater than 25% for the past three years, as illustrated in the chart below.

Based on recent well results and significant decreases in drilling and completion costs, we believe the Delaware Basin represents one of the most attractive operating regions in the United States. As illustrated in the chart below, according to data from IHS Performance Evaluator, in 2012, 2013, 2014 and 2015, wells in the Delaware Basin had a higher average three-month cumulative initial production per 1,000 feet of lateral section than wells in the Midland Basin, another sub-basin of the Permian Basin. These results are driven primarily by the over-pressured nature of the Bone Spring and Wolfcamp reservoirs in the Delaware Basin, which enhances the deliverability of horizontal wells. We believe these results indicate the Wolfcamp and the Bone Spring formations in the Delaware Basin

generate greater implied EURs per 1,000 feet of lateral length as compared to the Spraberry and Wolfcamp zones in the Midland Basin.

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

(1): Our total identified horizontal drilling locations include 48 locations associated with proved undeveloped reserves as of September 30, 2016. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, combined with our interpretation of available geologic and engineering data. In particular, we have analyzed and interpreted well results and other data acquired through our participation in the drilling of vertical wells that have penetrated our horizontal zones. In addition, to evaluate the prospectivity of our horizontal acreage, we have performed open-hole and mud log evaluations, core analysis and drill cuttings analysis. See "—Our Properties." The drilling locations that we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our ability to add additional proved reserves to our existing proved reserves. See "Risk Factors—Risks Related to Our Business—Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations." Further, to the extent the drilling locations are associated with acreage that expires, we would lose our right to develop the related locations. See "Risk Factors—Risks Related to Our Business—Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations."
(2): Our horizontal drilling location count implies 880-foot spacing with five to six wells per 640-acre section in the Wolfcamp zones and 1,320-foot spacing with four wells per 640-acre section in the 3rd Bone Spring Sandstone, in each case, consisting primarily of single-section (i.e., approximately 4,500-foot) laterals.
(3): 673 of our 1,388 horizontal drilling locations are on acreage that we operate. We have an approximate 84% average working interest in our operated acreage.
(4): We have included undeveloped horizontal locations only on our leasehold in Reeves and Ward counties.

We believe that development drilling of our 1,388 gross horizontal locations, with an increasing focus on drilling extended lateral wells as well as potential downspacing, will allow us to grow our production and reserves. In addition, we believe our large acreage blocks allow us to optimize our horizontal development program to maximize our resource recovery and our returns. We also intend to grow our production and reserves through acquisitions that meet our strategic and financial objectives. Furthermore, we believe our operational efficiency is enhanced by a third-party gas gathering system and cryogenic processing plant, which were built specifically for the area where the majority of our

acreage is located, and our operated saltwater disposal system. In addition, a third-party crude gathering system, which became operational in the third quarter of 2016 and will transport the majority of our crude oil to market at a lower cost than we have experienced historically, will provide additional efficiencies.

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

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

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

For the nine months ended September 30, 2016, our average net daily production was 7,982 Boe/d (approximately 69% oil, 20% natural gas and 11% NGLs). The following table provides summary information regarding our proved reserves as of December 31, 2015, based on a reserve report prepared by Netherland, Sewell & Associates, Inc., our independent petroleum engineer ("NSAI"). Of our proved reserves, approximately 40% were classified as PDP. PUDs included in this estimate are from 52 horizontal well locations across three zones.

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

Our properties include working interests in approximately 90,800 gross (42,300 net) surface acres, substantially all of which are located in the oil-rich core of the Southern Delaware Basin, a sub-basin of

the Permian Basin, in the Texas counties of Reeves, Ward and Pecos. The following table summarizes our surface acreage by county as of September 30, 2016.

Permian Basin. The Permian Basin consists of mature, legacy onshore oil and liquids-rich natural gas reservoirs that span approximately 86,000 square miles in West Texas and New Mexico. The Basin is composed of five sub regions: the Delaware Basin, the Central Basin Platform, the Midland Basin, the Northwest Shelf and the Eastern Shelf. The Permian Basin is an attractive operating area due to its multiple horizontal and vertical target zones, favorable operating environment, high oil and liquids-rich natural gas content, mature infrastructure, well-developed network of oilfield service providers, long-lived reserves with consistent reservoir quality and historically high drilling success rates. According to the EIA, the Permian Basin is the most prolific oil producing area in the U.S., accounting for 23% and 20% of total U.S. crude oil production during the twelve-month periods ended April 30, 2016 and April 30, 2015, respectively. Six key producing formations within the Permian Basin (Spraberry, Wolfcamp, Bone Spring, Glorieta, Yeso and Delaware) have provided the bulk of the Basin's 122% increase in oil production since 2007. Approximately 62% of the increase came from the Wolfcamp, Bone Spring and Spraberry formations.

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

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

We believe that our properties are prospective for oil and liquids-rich natural gas from multiple producing stratigraphic horizons, which we refer to as "stacked pay zones." For the nine months ended September 30, 2016, our net daily production averaged 69% oil, 20% natural gas and 11% NGLs and had a greater liquids-content than other areas of the Delaware Basin.

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

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

We operate approximately 80% of our net acreage and have an approximate 84% average working interest in our operated acreage. This operational control gives us flexibility in development strategy and pace. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, which suspension had no effect on our proved undeveloped reserves as of December 31, 2015, we added one horizontal drilling rig in June 2016, a second horizontal rig in September 2016 and a third horizontal rig in October 2016. During 2015, we operated, on average, one rig and placed 13 horizontal wells on production. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus on reducing drilling times, optimizing completions and reducing costs without compromising worker health, safety and environmental protection. For the nine months ended September 30, 2016, the spud-to-rig release for our three single-section horizontal wells was approximately 21 days compared to 28 days and 46 days for all single-section horizontal wells we drilled in 2015 and 2014, respectively. We expect that further optimization in the field (including the increased drilling of longer laterals, pad drilling, the use of shared facilities and zipper fracs), reduced rig rates and lower service costs will improve our well economics. In March 2016, we drilled and completed our first 9,500-foot lateral well, which had an initial 90-day oil production rate of approximately 900 barrels of oil per day.

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

incremental improvements in well performance and cost savings. Our philosophy is to focus on both parameters, with an emphasis on performance enhancement.

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

NSAI, our independent petroleum engineer, has estimated that as of December 31, 2015, proved reserves net to our interest in our properties were approximately 32,457 MBoe, of which 40% were classified as PDP. The proved reserves are generally characterized as long-lived, with predictable production profiles.

Production Status. For the nine months ended September 30, 2016, our average net daily production was 7,982 Boe/d (approximately 69% oil, 20% natural gas and 11% NGLs). During 2015, our average net daily production was 7,317 Boe/d (approximately 69% oil, 19% natural gas and 12% NGLs). As of September 30, 2016, we produced from 77 horizontal and 70 vertical wells, in each case, operated and non-operated.

Facilities. We strive to develop the necessary infrastructure to lower our costs and support our drilling schedule and production growth. We accomplish this goal primarily through contractual arrangements with third-party service providers. Our facilities located on our properties are generally in close proximity to our well locations and include storage tank batteries, oil/gas/water separation equipment and artificial lift equipment. A crude gathering system, which became operational in the third quarter of 2016 will transport the majority of our crude oil to market at a lower cost than we have experienced historically. For gas gathering and processing, we have infrastructure in place that spans the heart of our leasehold. The majority of our gas is processed at a cryogenic plant that is centrally located in our area of operations. We have a long-term agreement with a third-party gas gatherer and processor and benefit from priority producer status as the anchor tenant.

Recent and Future Activity. During the nine months ended September 30, 2016, 8.0 gross (5.1 net) wells were placed on production on our acreage. All of these wells were horizontal wells. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, we added one horizontal rig in June 2016, a second horizontal rig in September 2016 and a third horizontal rig in October 2016. During the remainder of 2016, 7 operated horizontal wells were either placed on production or were scheduled to be placed on production.

As of September 30, 2016, we had identified 1,388 gross horizontal drilling locations in the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C horizontal zones across our Delaware Basin acreage based on approximately 880-foot spacing for the Wolfcamp zones and 1,320-foot spacing for the 3rd Bone Spring Sandstone. Our drilling inventory includes 381 horizontal extended lateral locations of either 9,500 or 7,500 feet. Gross drilling locations are defined as locations on operated and non-operated leaseholds specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, combined with our interpretation of available geologic and engineering data. In particular, we have analyzed and interpreted well results and other data acquired through our participation in the drilling of vertical wells that have penetrated our horizontal zones. In addition, to evaluate the prospectivity of our horizontal acreage, we have performed open-hole and mud log evaluations, core analysis and drill cuttings analysis. The availability of local infrastructure, drilling support assets and other factors as management may deem relevant, such as easement restrictions and state and local regulations, are considered in determining such locations. The drilling locations for which we will actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.

Evaluation and Review of Proved Reserves. Our proved reserve estimates as of December 31, 2015 and 2014 were prepared by NSAI, our independent petroleum engineer. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Copies of our independent petroleum engineer's proved reserve reports as of December 31, 2015 and December 31, 2014 are included as Exhibit 99.2 and Exhibit 99.1, respectively, of the registration statement of which this prospectus forms a part. Our reserve report as of December 31, 2013 was prepared internally by our in-house petroleum engineers in accordance with (i) the same methodology utilized by NSAI in preparing its reports and (ii) the rules and regulations of the SEC.

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

with 37 years of reservoir and operations experience, and our geoscience staff has an average of approximately 24 years of energy industry experience.

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

Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a "high degree of confidence that the quantities will be recovered." All of our proved reserves as of December 31, 2015, 2014 and 2013 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for PDP wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developed non-producing ("PDNP") and PUD for our properties, due to the abundance of analog data.

To estimate economically recoverable proved reserves and related future net cash flows, NSAI considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a

grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Summary of Oil and Natural Gas Reserves. The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2015, 2014 and 2013, based on the proved reserve report as of December 31, 2015 and 2014 by NSAI, our independent petroleum engineer, and based on our internally prepared reserve report as of December 31, 2013, in each case, prepared in accordance with the rules and regulations of the SEC. Copies of the proved reserve reports as of December 31, 2015 and December 31, 2014 prepared by NSAI with respect to our properties are included as Exhibit 99.2 and Exhibit 99.1, respectively, to the registration statement of which this prospectus forms a part. All of our proved reserves are located in the United States.

	Year Ended December 31,

	2015(1)		2014(2)		2013(3)
Proved developed reserves:
Oil (MBbls)		9,347		8,026		6,021
Natural gas (MMcf)		12,711		11,959		4,837
NGLs (MBbls)		1,603		766		382

Total (MBoe)		13,068		10,786		7,210
Proved undeveloped reserves:
Oil (MBbls)		13,852		11,823		12,489
Natural gas (MMcf)		19,731		15,455		2,131
NGLs (MBbls)		2,248		785		143

Total (MBoe)		19,389		15,184		12,987
Total proved reserves:
Oil (MBbls)		23,199		19,850		18,510
Natural gas (MMcf)		32,442		27,414		6,968
NGLs (MBbls)		3,851		1,551		525

Total (MBoe)		32,457		25,970		20,197
Oil and Natural Gas Prices:
Oil—WTI posted price per Bbl	$	46.79	$	91.48	$	95.96
Natural gas—Henry Hub spot price per MMBtu	$	2.59	$	4.35	$	3.67

(2): Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.48 per barrel as of December 31, 2014 was adjusted for quality, transportation fees and a regional price differential. For gas volumes, the average Henry Hub spot price of $4.35 per MMBtu as of December 31, 2014 was adjusted for energy content, transportation fees and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $84.94 per barrel of oil, $22.70 per barrel of NGL and $4.70 per Mcf of gas as of December 31, 2014.
(3): Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil and NGL volumes, the average West Texas Intermediate posted price of $95.96 per barrel as of December 31, 2013 was adjusted for quality, transportation fees and a regional price differential. For gas volumes, the average Henry Hub spot price of $3.67 per MMBtu as of December 31, 2013 was adjusted for energy content, transportation fees and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $92.05 per barrel of oil, $26.05 per barrel of NGL and $3.76 per Mcf of gas as of December 31, 2013.

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

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

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

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

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

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

During the twelve months ended December 31, 2015, we spent $17.7 million to convert PUDs to proved developed reserves.

All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking. As of December 31, 2015, none of our total proved reserves were classified as PDNP

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

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

During the twelve months ended December 31, 2014, we spent $10.6 million to convert PUDs to proved developed reserves.

All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking. As of December 31, 2014, 0.2% of our total proved reserves were classified as PDNP.

As of December 31, 2013, our PUDs totaled 12,489 MBbls of oil, 2,131 MMcf of natural gas and 143 MBbls of NGLs, for a total of 12,987 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Changes in PUDs that occurred during 2013 were primarily due to (i) additions of approximately 5,430 MBoe attributable to improved recovery resulting from the application of tertiary recovery methods utilizing CO2 injection on properties in Chaves County, New Mexico that we sold in May 2014; (ii) a decrease of approximately 6,707 MBoe related to the Wolfbone Disposition in October 2013, the sale of our interest in 320 gross (187 net) acres in Glasscock and Midland Counties, Texas, including two wells, in June 2013, and the sale of our interest in 1,951 gross (1,617 net) acres in Midland County, Texas, including ten wells, in August 2013; (iii) additions of approximately 4,038 MBoe attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position and (iv) the conversion of approximately 402 MBoe attributable to PUDs into proved developed reserves.

During the twelve months ended December 31, 2013, we spent $7.5 million to convert PUDs to proved developed reserves and $144.0 million to convert non-proved reserves to proved developed reserves.

All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking. As of December 31, 2013, 2% of our total proved reserves were classified as PDNP.

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

	Nine Months Ended September 30,				Year Ended December 31,

	2016		2015		2015		2014		2013
	(In thousands)
Production data:
Oil (MBbls)		1,520		1,329		1,830		1,428		713
Natural gas (MMcf)		2,551		2,205		3,058		2,112		797
NGLs (MBbls)		242		242		331		235		98

Total (MBoe)(1)		2,187		1,939		2,671		2,015		944
Average realized prices before effects of hedges:
Oil (per Bbl)	$	37.48	$	44.45	$	42.43	$	80.50	$	92.37
Natural gas (per Mcf)		2.24		2.76		2.60		4.58		3.79
NGLs (per Bbl)		12.80		14.83		14.66		30.64		31.50

Total (per Boe)	$	30.08	$	35.45	$	33.87	$	65.42	$	76.24
Average realized prices after effects of hedges:
Oil (per Bbl)	$	48.42	$	63.30	$	61.61	$	83.73	$	74.68
Natural gas (per Mcf)		2.24		3.18		3.04		4.58		3.79
NGLs (per Bbl)		12.80		14.83		14.66		30.64		31.50

Total (per Boe)	$	37.68	$	48.85	$	47.51	$	67.71	$	62.84
Average costs (per Boe):
Lease operating expenses	$	4.71	$	8.93	$	7.93	$	8.78	$	20.24
Severance and ad valorem taxes		1.61		1.98		1.88		3.41		4.40
Transportation, processing, gathering and other operating expenses		2.00		2.24		2.15		2.37		1.37
Depreciation, depletion, amortization and accretion of asset retirement obligations		27.86		33.01		33.73		34.30		31.02
Abandonment expense and impairment of unproved properties		1.16		1.99		2.85		9.94		9.07
Exploration		—		—		0.03		—		—
Contract termination and rig stacking		—		1.23		0.89		—		—
General and administrative expenses		4.87		4.40		5.32		15.73		17.84

Total	$	42.21	$	53.78	$	54.78	$	74.53	$	83.94

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

The following table sets forth information as of September 30, 2016 relating to our leasehold acreage. Developed acreage consists of acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

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

The following table sets forth the results of our drilling activity, as defined by wells having been placed on production, for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

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

	2016				2015				2015				2014				2013
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive(1)		—		—		—		—		—		—		—		—		—		—
Dry		—		—		—		—		—		—		—		—		—		—

Total Exploratory		—		—		—		—		—		—		—		—		—		—



Development Wells:
Productive(1)		8.0		5.1		9.0		8.1		16.0		12.4		36.0		26.8		26.0		10.9
Dry				—		—		—		—		—		—		—		—		—

Total Development		8.0		5.1		9.0		8.1		16.0		12.4		36.0		26.8		26.0		10.9



Total Wells:
Productive(1)		8.0		5.1		9.0		8.1		16.0		12.4		36.0		26.8		26.0		10.9
Dry				—		—		—		—		—		—		—		—		—

Total		8.0		5.1		9.0		8.1		16.0		12.4		36.0		26.8		26.0		10.9

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

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

We normally sell production to a relatively small number of customers, as is customary in our business. For the years ended December 31, 2015, 2014 and 2013, Plains Marketing, L.P. accounted for

64%, 78% and 72%, respectively, of our total revenue. During such years, no other purchaser accounted for 10% or more of our revenue. In the third quarter of 2016, we started selling the majority of our oil production to Shell under a new marketing contract. The loss of Shell as a purchaser could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of Shell as a purchaser would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

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

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

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

Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. Due to these

seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

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

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

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 80%.

Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the development and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of

drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, FERC and the courts. We cannot predict when or whether any such proposals may become effective.

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

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

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

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

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

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We rely on third-party pipelines

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

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

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

The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provided FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increased FERC's civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. On June 29, 2016, FERC issued an order (Order No. 826) increasing the maximum civil penalty amounts under the NGA and NGPA to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of $1,193,970 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, use or employ any device, scheme or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC's NGA enforcement authority.

We are required to observe such anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act ("CEA"), and regulations

promulgated thereunder by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should we violate the anti-market manipulation laws and regulations, it could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

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

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

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

Our oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

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

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

The Resource Conservation and Recovery Act ("RCRA") and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA's less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, from time to time various environmental groups have challenged the EPA's exemption of certain oil and gas wastes from RCRA. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial

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

We currently own, lease or operate numerous properties that have been used for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the "Corps"). In September 2015, the EPA and the Corps issued new rules defining the scope of the EPA's and the Corps' jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands. To the extent the rule expands the scope of the Clean Water Act's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of the Clean Water Act, and implementation of the rule has been stayed pending resolution of the court challenge. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

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

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 ("OPA"), which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain "responsible parties" related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines.

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

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

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 hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which requires member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The agreement was signed in April 2016, and is expected to enter into force in November 2016. The United States is one of over 70 nations having ratified or otherwise consented to be bound by the agreement. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our operations.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming struck down this rule. The BLM has appealed this decision. The appeal remains pending. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require

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.

The Endangered Species Act ("ESA") and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species' habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency's 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government recently issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

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

that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

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

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

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

As of November 15, 2016, we had 53 full-time employees. We hire independent contractors on an as needed basis, and have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

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

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

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

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

We have no direct operations and no significant assets other than the ownership of an approximate 89% 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.

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 are to CRP and its operations prior to the Closing.

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.

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 thus far in 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 thus far 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.

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.

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

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

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Oil sales contributed 87% of our total revenues for the first half of 2016. Natural gas sales contributed 8% and NGL sales contributed 5% of our total revenues for the first half of 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.

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:

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.

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.

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

Lease Operating Expenses. Lease operating expenses ("LOE") are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, materials and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased LOE in periods during which they are performed. Certain of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production-related activities, such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production.

We monitor our operations to ensure that we are incurring LOE at an acceptable level. For example, we monitor our LOE per Boe to determine if any wells or properties should be shut in, recompleted or sold. This unit rate also allows us to monitor these costs in certain fields and

geographic areas to identify trends and to benchmark against other producers. Although we strive to reduce our LOE, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate our properties or make acquisitions and dispositions of properties. For example, we may increase field level expenditures to optimize our operations, incurring higher expenses in one quarter relative to another, or we may acquire or dispose of properties that have different LOE per Boe. These initiatives would influence our overall operating cost and could cause fluctuations when comparing LOE on a period to period basis.

Severance and Ad Valorem Taxes. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by federal, state or local taxing authorities. In general, the severance taxes we pay correlate to the changes in oil, natural gas and NGLs revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices.

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

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

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

General and Administrative Expenses. General and administrative ("G&A") expenses are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other fees for professional services and legal compliance.

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

Interest Expense. A portion of our working capital requirements and capital expenditures are financed with borrowings under CRP's revolving credit facility and term loan. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under CRP's revolving credit facility and term loan in interest expense.

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").

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 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.

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	%

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.

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.

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.

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

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.

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	%

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.

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

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:

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.

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.

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	%

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.

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.

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:

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

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.

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 is approximately $92 million, excluding leasing and other acquisitions. In the nine months ended

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, CRP repaid all amounts outstanding under its revolving credit facility and term loan.

Based upon current oil and natural gas price expectations for the remainder of 2016 and 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.

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 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.

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.

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 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.

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.

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. As of the Closing Date, CRP had no outstanding debt and approximately $100.0 million of cash on hand.

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, in 2016 and thereafter, 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 April 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:

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

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

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

(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 PennTex Midstream Partners, LP 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.

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.

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 thus far in 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.

Description & Production Period		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	)

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.

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.

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.

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.

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.

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.

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.

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 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.

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.

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.

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.

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.

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 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.

Set forth below are the names, ages and positions of each of each of our directors and executive officers:

Mark G. Papa has been our Chief Executive Officer and a director since November 2015. Since the closing of the Business Combination, Mr. Papa also serves as our President. Mr. Papa is a Houston-based advisor to Riverstone. We currently anticipate that Mr. Papa will spend approximately 60% of his working time providing services to us as our President and Chief Executive Officer and approximately 40% of his working time providing services to Riverstone on matters unrelated to the Company. Prior to joining Riverstone in February 2015, Mr. Papa was Chairman and CEO of EOG Resources, Inc. (NYSE: EOG), an independent U.S. oil and gas company, from August 1999 to December 2013. Mr. Papa served as a member of EOG Resources' board of directors from August 1999 until December 2014. Mr. Papa worked at EOG Resources for 32 years in various management positions. Mr. Papa was retired from December 2013 through February 2015. Prior to joining EOG Resources, Mr. Papa worked at Conoco Inc. for 13 years in various engineering and management positions. Mr. Papa has also served on the board of Oil States Industries (NYSE: OIS), a multinational oil and gas company, since February 2001 and Casa de Esperanza, a non-profit organization serving immigrants, since November 2006. In February 2010 and 2013, the Harvard Business Review cited Mr. Papa as one of the 100 Best Performing CEOs in the World; both times Mr. Papa was the highest ranked Global Energy CEO. Additionally, Institutional Investor magazine repeatedly ranked him as the Top Independent E&P CEO. He received his B.S. in petroleum engineering from the University of Pittsburgh and an MBA from the University of Houston. We believe Mr. Papa's significant experience in the energy industry make him well qualified to serve as a member of the board of directors.

George S. Glyphis has been our Chief Financial Officer since the closing of the Business Combination. He has served as Vice President and Chief Financial Officer of Centennial Resource Management, LLC (the "Management Company") since July 2014. Prior to joining the Management Company, Mr. Glyphis served as a Managing Director in the Oil & Gas Investment Banking practice at J.P. Morgan where his client base comprised primarily upstream and integrated oil and gas companies.

In his 21 years at J.P. Morgan, Mr. Glyphis led the origination and execution of transactions including initial public offerings, equity follow-on offerings, high yield and investment grade bond offerings, corporate mergers and acquisitions, asset acquisition and divestitures, and reserve-based and corporate lending. Mr. Glyphis earned his B.A. in History from the University of Virginia.

Sean R. Smith has been our Chief Operating Officer since the closing of the Business Combination. Mr. Smith has served as the Vice President, Geosciences of CRP since May 2014. Prior to joining CRP, from February 2013 to May 2014, Mr. Smith worked at QEP Resources, where he served in several roles, including as a General Manager, leading the geoscience, regulatory and reservoir engineering departments for the Williston, Powder River, and Denver Julesburg Basins. Prior to QEP Resources, from 2005 to February 2013, Mr. Smith worked at Resolute Energy Corporation as a Manager and Geologist. He has also worked in various geotechnical roles at Kerr-McGee and Sanchez Oil & Gas. Mr. Smith earned his B.A. in Geology from Lawrence University. He is licensed with the Texas Board of Professional Geoscientists and is a member of the American Association of Petroleum Geologists.

Maire A. Baldwin has served as a director since the closing of the Business Combination. Ms. Baldwin was employed as an Advisor to EOG from March 2015 until April 2016. Prior to that, she was employed at EOG as Vice President Investor Relations from 1996-2014. Ms. Baldwin has served as a director of the Houston Parks Board since 2011, a non-profit dedicated to developing parks and green space to the greater Houston area where she serves on several committees. She is co-founder of Pursuit, a non-profit dedicated to raising funds and awareness of adults with intellectual and developmental disabilities. Ms. Baldwin has an MBA from the University of Texas at Austin and a B.A. in Economics from the University of Texas at Austin. Ms. Baldwin was selected to serve on the board of directors due to her extensive experience in the energy industry.

Robert M. Tichio has served as a director since the closing of the Business Combination. Mr. Tichio is a Partner of Riverstone and joined Riverstone in 2006. Prior to joining Riverstone, Mr. Tichio was in the Principal Investment Area of Goldman Sachs which manages the firm's private corporate equity investments. Mr. Tichio began his career at J.P. Morgan in the Mergers & Acquisitions group where he concentrated on assignments that included public company combinations, asset sales, takeover defenses and leveraged buyouts. In addition to serving on the boards of a number of Riverstone portfolio companies and their affiliates, Mr. Tichio has been a director of Northern Blizzard Resources Inc. since June 2011 and a director EP Energy Corporation since September 2013. Mr. Tichio previously served as a member of the board of directors of Gibson Energy (TSE:GEI) from 2008 to 2013 and Midstates Petroleum Company, Inc. from 2012 to 2015. He holds an MBA from Harvard Business School and a bachelor's degree from Dartmouth College. Mr. Tichio was selected to serve on the board of directors due to his extensive private equity and mergers and acquisitions experience.

Karl E. Bandtel has served as a director since the closing of the Business Combination. Mr. Bandtel was a Partner at Wellington Management Company, where he managed energy portfolios, from 1997 until June 30, 2016 when he retired. He holds a Master's degree in business from the University of Wisconsin—Madison and a bachelor's degree from University of Wisconsin—Madison. Mr. Bandtel was selected to serve on the board of directors due to his extensive experience in investing in energy companies, both public and private.

Jeffrey H. Tepper has served as a director since the completion of our IPO in February 2016. Mr. Tepper is Founder of JHT Advisors LLC, an M&A advisory and investment firm. From 1990 to 2013, Mr. Tepper served in a variety of senior management and operating roles at the investment bank Gleacher & Company, Inc. and its predecessors and affiliates. Mr. Tepper was Head of Investment Banking and a member of the Firm's Management Committee. Mr. Tepper is experienced in mergers & acquisitions, corporate finance, leveraged finance and asset management. Mr. Tepper is also the former

Chief Operating Officer overseeing operations, compliance, technology and financial reporting. In 2001, Mr. Tepper co-founded Gleacher's asset management activities and served as President. Gleacher managed over $1 billion of institutional capital in the mezzanine capital and fund of hedge fund areas. Mr. Tepper served on the Investment Committees of Gleacher Mezzanine and Gleacher Fund Advisors. Between 1987 and 1990, Mr. Tepper was employed by Morgan Stanley & Co. as a financial analyst in the mergers & acquisitions and merchant banking departments. Mr. Tepper received an MBA from Columbia Business School and a BS in Economics from The Wharton School of the University of Pennsylvania with concentrations in finance and accounting. Mr. Tepper was selected to serve on the board of directors due to his significant investment and financial experience.

David M. Leuschen has served as a director since the closing of the Business Combination. Mr. Leuschen is a Founder of Riverstone and has been a Senior Managing Director since 2000. Prior to founding Riverstone, Mr. Leuschen was a Partner and Managing Director at Goldman Sachs and founder and head of the Goldman Sachs Global Energy and Power Group. Mr. Leuschen joined Goldman Sachs in 1977, became head of the Global Energy and Power Group in 1985, became a Partner of that firm in 1986 and remained with Goldman Sachs until leaving to found Riverstone in 2000. Mr. Leuschen also served as Chairman of the Goldman Sachs Energy Investment Committee, where he was responsible for screening potential capital commitments by Goldman Sachs in the energy and power industry and was responsible for establishing and managing the firm's relationships with senior executives from leading companies in all segments of the energy and power industry. Mr. Leuschen serves as a non-executive board member of Riverstone Energy Limited (LSE: REL) since May 2013 and serves on the boards of directors or equivalent bodies of a number of private Riverstone portfolio companies and their affiliates. In 2007, Mr. Leuschen, along with Riverstone and The Carlyle Group ("Carlyle"), became the subject of an industry-wide inquiry by the Office of the Attorney General of the State of New York (the "Attorney General") relating to the use of placement agents in connection with investments by the New York State Common Retirement Fund ("NYCRF") in certain funds, including funds that were jointly developed by Riverstone and Carlyle. In June 2009, Riverstone entered into an Assurance of Discontinuance with the Attorney General to resolve the matter and agreed to make a restitution payment of $30 million to the New York State Office of the Attorney General for the benefit of NYCRF. Mr. Leuschen also entered into an Assurance of Discontinuance with the Attorney General in December 2009 and agreed that Riverstone and/or Mr. Leuschen would make a restitution payment of $20 million to the New York State Office of the Attorney General for the benefit of NYCRF. Mr. Leuschen has received an MBA from Dartmouth's Amos Tuck School of Business and an A.B. degree from Dartmouth College. Mr. Leushen was selected to serve on the board of directors due to his extensive mergers and acquisitions, financing and investing experience in the energy and power industry.

Pierre F. Lapeyre, Jr. has served as a director since the closing of the Business Combination. Mr. Lapeyre is a Founder of Riverstone and has been a Senior Managing Director since 2000. Prior to founding Riverstone, Mr. Lapeyre was a Managing Director of Goldman Sachs in its Global Energy and Power Group. Mr. Lapeyre joined Goldman Sachs in 1986 and spent his 14-year investment banking career focused on energy and power, particularly the midstream, upstream and energy service sectors. Mr. Lapeyre serves as a non-executive board member of Riverstone Energy Limited (LSE: REL) since May 2013 and serves on the boards of directors or equivalent bodies of a number of private Riverstone portfolio companies and their affiliates. He has an MBA from the University of North Carolina at Chapel Hill and a B.S. in Finance and Economics from the University of Kentucky. Mr. Lapeyre was selected to serve on the board of directors due to his extensive mergers and acquisitions, financing and investing experience in the energy and power industry.

Tony R. Weber has served as a director since the closing of the Business Combination. Mr. Weber joined Natural Gas Partners in December 2003 and has served as a Managing Partner since November 2013. He previously served Natural Gas Partners in other capacities, including Managing Director from

2007 to November 2013. Prior to joining Natural Gas Partners, Mr. Weber was the Chief Financial Officer of Merit Energy Company from April 1998 to December 2003. Prior to that, he was Senior Vice President and Manager of Union Bank of California's Energy Division in Dallas, Texas from 1987 to 1998. From September 2011 to September 2016, Mr. Weber served as the Chairman of the Board for Memorial Resource Development, Inc., and from September 2011 to March 2016, he served as a director of the general partner of Memorial Production Partners LP. Mr. Weber received a B.B.A. in Finance in 1984 from Texas A&M University. Mr. Weber was selected to serve on the board of directors due to his extensive corporate finance, banking and private equity experience. Mr. Weber was nominated and elected to the board of directors by CRD which, as the holder of our Series A Preferred Stock, is entitled to nominate and elect one director to the board of directors for so long as the Centennial Contributors hold at least 5,000,000 CRP Common Units and/or shares of Class A Common Stock (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar transactions).

We are managed under the direction of our board of directors. Our board of directors is divided into three classes of directors with only one class of directors being elected in each year and each class (except those directors appointed prior to our first annual meeting of stockholders) serving a three-year term. The term of office of the first class of directors, consisting of Maire A. Baldwin and Robert M. Tichio, will expire at our first annual meeting of stockholders. The term of office of the second class of directors, Jeffrey H. Tepper and Karl E. Bandtel, will expire at the second annual meeting of stockholders. The term of office of the third class of directors, consisting of Mark G. Papa, David M. Leuschen and Pierre F. Lapeyre, Jr., will expire at the third annual meeting of stockholders. In addition, one director, initially Tony R. Weber, will be nominated and elected by CRD as the holder of our Series A Preferred Stock. The term of office of Mr. Weber will expire at our first annual meeting of stockholders.

Officers are appointed by the board of directors and serve at discretion of the board, rather than for specific terms of office.

Affiliates of Riverstone Investment Group LLC control a majority of the combined voting power of all classes of our voting stock. As a result, we qualify as a "controlled company" within the meaning of the listing standards of the NASDAQ and we have elected not to comply with certain NASDAQ corporate governance requirements. Therefore, we do not have a majority of independent directors serving on our board and have individuals serving on our compensation committee and corporate governance and nominating committee that do not qualify as independent according to NASDAQ listing standards and the rules and regulations of the SEC. These independence requirements will not apply to us as long as we remain a controlled company.

Our board of directors has determined that Ms. Maire A. Baldwin and Messrs. Karl E. Bandtel, Jeffrey H. Tepper and Tony R. Weber are independent within the meaning of NASDAQ Rule 5605(a)(2).

The standing committees of our board of directors currently consists of an audit committee (the "Audit Committee"), a compensation committee (the "Compensation Committee") and a corporate governance and nominating committee (the "Corporate Governance and Nominating Committee"). Each of the committees report to the board of directors as they deem appropriate and as the board may request. The composition, duties and responsibilities of these committees are set forth below.

The principal functions of our Audit Committee are detailed in the Audit Committee charter, which is available on our website, and include:

Our Audit Committee consists of Messrs. Jeffrey H. Tepper and Karl E. Bandtel and Ms. Maire A. Baldwin, with Mr. Tepper serving as the Chair. We believe that Messrs. Tepper and Bandtel and Ms. Baldwin qualify as independent directors according to the rules and regulations of the SEC with respect to audit committee membership. We also believe that Mr. Tepper qualifies as our "audit committee financial expert," as such term is defined in Item 401(h) of Regulation S-K.

The principal functions of our Compensation Committee are detailed in the Compensation Committee charter, which is available on our website, and include:

Our Compensation Committee consists of Ms. Maire A. Baldwin and Messrs. Pierre F. Lapeyre, Jr., Jeffrey H. Tepper and Robert M. Tichio, with Mr. Lapeyre serving as the Chair.

The Compensation Committee may delegate the approval of certain transactions to a subcommittee consisting solely of two or more members of the Compensation Committee who are "non-employee directors" for the purposes of Rule 16b-3 under the Exchange Act and "outside directors" for the purposes of Section 162(m) of the U.S. Internal Revenue Code of 1986, as amended (the "Code"). On October 27, 2016, the Compensation Committee created a subcommittee (the "Section 162(m) Plan Subcommittee") consisting of Ms. Baldwin and Mr. Tepper to administer and make determinations from time to time with respect to awards granted or compensation to be provided under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the "LTIP") or any successor plan, including compensation that is intended to qualify as "performance-based compensation" under Section 162(m) of the Code, and the regulations promulgated thereunder. The Compensation Committee has determined that Ms. Baldwin and Mr. Tepper are both "non-employee directors" for the purposes of Rule 16b-3 under the Exchange Act and "outside directors" for the purposes of Section 162(m) of the Code. The charter of the Section 162(m) Plan Subcommittee is available on our website.

The principal functions of our Corporate Governance and Nominating Committee are detailed in the Corporate Governance and Nominating Committee charter, which is available on our website, and include:

The Corporate Governance and Nominating Committee also develops and recommends to the board of directors corporate governance principles and practices and assists in implementing them, including conducting a regular review of our corporate governance principles and practices. The Corporate Governance and Nominating Committee oversees the annual performance evaluation of the board of directors and the committees of the board of directors and makes a report to the board of directors on succession planning.

Our Corporate Governance and Nominating Committee consists of Messrs. David M. Leuschen, Tony R. Weber and Robert M. Tichio, with Mr. Leuschen serving as the Chair.

During 2016, no officer or employee served as a member of our Compensation Committee. None of our executive officers serve as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving on our board of directors or Compensation Committee.

The following disclosure concerns the compensation of the Company's officers and directors before the Closing. See "—Compensation of Executive Officers and Directors after the Business Combination" below for a description of the compensation of our current executive officers following the Closing.

Other than as described below, prior to the Closing, none of the Company's officers or directors received any cash compensation from the Company for services rendered to the Company. From our formation through the Closing, we did not grant any stock options, stock appreciation rights or any other awards under long-term incentive plans to any of our officers or directors. On February 23, 2016, we entered into an administrative support agreement pursuant to which we agreed to pay an affiliate of our Sponsor a total of $10,000 per month for office space, utilities and secretarial and administrative support. Following the Closing, we no longer pay these monthly fees. This arrangement was agreed to for our benefit and was not intended to provide compensation in lieu of a salary or other remuneration. We believe the $10,000 per month fee was at least as favorable as we could have obtained from an unaffiliated third party for the services. Other than the $10,000 per month fee to our Sponsor's affiliate, no compensation of any kind, including finder's and consulting fees, was paid to our Sponsor, officers and directors, or any of their respective affiliates, for services rendered prior to or in connection with the completion of the Business Combination. However, our Sponsor, officers and directors, or any of their respective affiliates, were reimbursed for any out-of-pocket expenses incurred in connection with activities on our behalf, such as identifying potential target businesses and performing due diligence on suitable business combinations. Our Audit Committee reviewed on a quarterly basis all payments that were made to our Sponsor, officers, directors or their affiliates.

The following disclosure concerns the pre-Business Combination compensation of CRP's executive officers and directors and is presented based on the reduced disclosure rules applicable to CRP as an "emerging growth company" within the meaning of the Securities Act.

During 2015 and through the Closing, CRP's executive officers were employees of the Management Company, a wholly owned subsidiary of CRD, and provided services to CRD and CRP pursuant to management services agreements between such entities. In connection with the Closing, CRD contributed its interests in the Management Company to CRP and CRP's executive officers and the other employees providing services to CRP became employees of a wholly owned subsidiary of CRP. Following the Closing, with respect to CRP's named executive officers, Messrs. Polzin and Siepman provided transition services as non-executive officer employees for a short period and are no longer employed by us. Mr. Glyphis serves as our Chief Financial Officer. See "—Compensation of Executive Officers and Directors after the Business Combination" below for a description of Mr. Glyphis's compensation following the Closing.

CRP's named executive officers have received awards of "incentive units" (the "CRD Incentive Units") pursuant to the limited liability company agreement of CRD (as amended from time to time, the "CRD LLC Agreement"). The CRD Incentive Units are intended to constitute "profits interests" and represent actual (non-voting) equity interests in CRD that have no liquidation value for U.S. federal income tax purposes on the date of grant but are designed to gain value only after the underlying assets have realized a certain level of growth and return to those persons who hold certain other classes of CRD's equity.

CRP's named executive officers have also received awards of "incentive units" (the "NGP Follow-On Incentive Units") pursuant to the limited liability company agreement of NGP Follow-On (as amended from time to time, the "NGP Follow-On LLC Agreement"). The NGP Follow-On Incentive Units are intended to constitute "profits interests" and represent actual (non-voting) equity interests in NGP Follow-On that have no liquidation value for U.S. federal income tax purposes on the date of grant but are designed to gain value only after the underlying assets have realized a certain level of growth and return to those persons who hold certain other classes of NGP Follow-On's equity.

We believe that, despite the fact that the CRD Incentive Units and NGP Follow-On Incentive Units do not require the payment of an exercise price, these awards are most similar economically to stock options and, as such, they are properly classified as "options" for purposes of the SEC's executive compensation disclosure rules under the definition provided in Item 402(m)(5)(i) of Regulation S-K since these awards have "option-like features."

The following table reflects information regarding outstanding incentive units held by CRP's named executive officers as of December 31, 2015. See "—Narrative Disclosures—Incentive Units" below for additional information about these awards. As the incentive units are equity interests in CRD and NGP Follow-On, the incentive units held by CRP's named executive officers do not relate directly to CRP's securities, and CRP is not responsible for making any payments, distributions or settlements to any award recipient relating to such incentive units. CRD and NGP Follow-On are currently

responsible for making all payments, distributions and settlements to all award recipients relating to the CRD Incentive Units and NGP Follow-On Incentive Units.

	Option Awards(1)

Name	Number of Securities Underlying Unexercised Options, Exercisable (#)		Number of Securities Underlying Unexercised Options, Unexercisable (#)		Option Exercise Price ($)		Option Expiration Date
Ward Polzin
CRD Incentive Units
CRD Tier I Units		154,000		176,000		N/A		N/A
CRD Tier II Units		154,000		176,000		N/A		N/A
CRD Tier III Units		0		330,000		N/A		N/A
CRD Tier IV Units		0		330,000		N/A		N/A
CRD Tier V Units		0		330,000		N/A		N/A
NGP Follow-On Incentive Units
NGP Follow-On Tier I Units		44,000		286,000		N/A		N/A
NGP Follow-On Tier II Units		44,000		286,000		N/A		N/A
NGP Follow-On Tier III Units		0		330,000		N/A		N/A
NGP Follow-On Tier IV Units		0		330,000		N/A		N/A
NGP Follow-On Tier V Units		0		330,000		N/A		N/A
George S. Glyphis
CRD Incentive Units
CRD Tier I Units		25,000		75,000		N/A		N/A
CRD Tier II Units		25,000		75,000		N/A		N/A
CRD Tier III Units		0		100,000		N/A		N/A
CRD Tier IV Units		0		100,000		N/A		N/A
CRD Tier V Units		0		100,000		N/A		N/A
NGP Follow-On Incentive Units
NGP Follow-On Tier I Units		13,333		86,667		N/A		N/A
NGP Follow-On Tier II Units		13,333		86,667		N/A		N/A
NGP Follow-On Tier III Units		0		100,000		N/A		N/A
NGP Follow-On Tier IV Units		0		100,000		N/A		N/A
NGP Follow-On Tier V Units		0		100,000		N/A		N/A
Bret Siepman
CRD Incentive Units
CRD Tier I Units		77,000		88,000		N/A		N/A
CRD Tier II Units		77,000		88,000		N/A		N/A
CRD Tier III Units		0		165,000		N/A		N/A
CRD Tier IV Units		0		165,000		N/A		N/A
CRD Tier V Units		0		165,000		N/A		N/A
NGP Follow-On Incentive Units
NGP Follow-On Tier I Units		22,000		143,000		N/A		N/A
NGP Follow-On Tier II Units		22,000		143,000		N/A		N/A
NGP Follow-On Tier III Units		0		165,000		N/A		N/A
NGP Follow-On Tier IV Units		0		165,000		N/A		N/A
NGP Follow-On Tier V Units		0		165,000		N/A		N/A

CRP historically has not maintained any employment, severance or change in control agreements with its named executive officers. In addition, CRP's named executive officers are not entitled to any payments or other benefits in connection with a termination of employment or a change in control, other than with respect to incentive units as described below under "—Incentive Units."

CRP has not maintained, and neither we nor CRP currently intend to maintain, a defined benefit pension plan or nonqualified deferred compensation plan. Instead, CRP's employees, including CRP's named executive officers, have participated in a retirement plan intended to provide benefits under section 401(k) of the Code (the "401(k) Plan") pursuant to which employees are allowed to contribute a portion of their base compensation to a tax-qualified retirement account. The 401(k) Plan provides for matching contributions equal to 100% of the first 6% of employees' eligible compensation contributed to the 401(k) Plan. Employees are immediately 100% vested in the matching contributions made to their 401(k) Plan account and are always 100% vested in the employee contributions they make to their 401(k) Plan account. Employees may generally receive a distribution of the vested portion of their 401(k) Plan account upon (i) a termination of employment, (ii) normal retirement, (iii) disability or (iv) death.

CRD Incentive Units. In 2013, certain executive officers of CRP received an award of CRD Incentive Units, or profits interests that represent actual (non-voting) equity interests in CRD, in order to provide them with the ability to benefit from the growth in CRD's operations and business. The CRD Incentive Units are divided into five tiers, with each tier currently comprised of one tranche. A potential payout for each tranche will occur when a certain specified level of cumulative cash distributions has been received by the capital interest holding members of CRD. Tier I units and Tier II units each vest in five equal annual installments beginning on the first anniversary of the applicable date of grant (with vesting between such anniversaries occurring pro rata each month), subject to full accelerated vesting upon the occurrence of either (i) (a) with respect to the Tier I units, satisfaction of the payment threshold established for the Tier I units or (b) with respect to the Tier II units, satisfaction of the payment threshold established for the Tier II units or (ii) with respect to both Tier I units and Tier II units, a "Fundamental Change" (as defined below). Tier III units, Tier IV units and Tier V units each vest only upon satisfaction of the payment threshold established for the applicable tier. All CRD Incentive Units that have not yet vested according to their applicable vesting requirements will automatically be forfeited and become null and void at the time a named executive officer's employment is terminated for any reason; provided, however, that, prior to such forfeiture, solely with respect to any unvested CRD Incentive Units that are Tier I or Tier II units, the named executive officer will vest, immediately prior to his termination of employment, as to a pro rata amount of such unvested CRD Incentive Units determined by multiplying the number of CRD Incentive Units that would vest on the next annual vesting date by a fraction with a numerator equal to the number of full months that have elapsed since the most recent vesting date and a denominator of 12, with such pro rata amount rounded to the closest whole number. If a named executive officer's employment is terminated for "cause" (as defined below), or the named executive officer resigns or terminates the

service relationship early (each, a "voluntary termination"), all vested CRD Incentive Units will be forfeited at the time of the termination. In the event that a named executive officer's employment is terminated other than (i) for cause or (ii) due to a voluntary termination, the named executive officer will retain all vested CRD Incentive Units following such termination. For purposes of the foregoing, a named executive officer's termination of employment means the termination of such named executive officer's employment with CRP, CRD, NGP Follow-On and all of its affiliates.

The Tier I units entitle Tier I unitholders to 20% of future distributions, Tier II units entitle Tier II unitholders to 5% of future distributions, Tier III units entitle Tier III unitholders to 5% of future distributions, Tier IV units entitle Tier IV unitholders to 5% of future distributions and Tier V units entitle Tier V unitholders to 5% of future distributions, in each case, only after all of the members that have made capital contributions to CRD have received cumulative cash distributions in respect of their membership interests equal to, for each tier, a certain factor times their cumulative capital contributions.

The consummation of the Business Combination resulted in a Fundamental Change with respect to the CRD Incentive Units. Because neither the Company nor CRP is a party to the CRD LLC Agreement, neither the Company nor CRP can be certain that the terms of the CRD Incentive Units and CRD LLC Agreement will remain the same in the future.

NGP Follow-On Incentive Units. In 2015, each named executive officer of CRP received an award of NGP Follow-On Incentive Units, or profits interests that represent actual (non-voting) equity interests in NGP Follow-On. The NGP Follow-On Incentive Units are divided into five tiers, with each tier currently comprised of one tranche. A potential payout for each tranche will occur when a certain specified level of cumulative cash distributions has been received by the capital interest holding members of NGP Follow-On. Tier I units and Tier II units each vest in five equal annual installments beginning on the first anniversary of the applicable date of grant (with vesting between such anniversaries occurring pro rata each month), subject to full accelerated vesting upon the occurrence of either (i) (a) with respect to the Tier I units, satisfaction of the payment threshold established for the Tier I units or (b) with respect to the Tier II units, satisfaction of the payment threshold established for the Tier II units or (ii) with respect to both Tier I units and Tier II units, a "Fundamental Change" (as defined below). Tier III units, Tier IV units and Tier V units each vest only upon satisfaction of the payment threshold established for the applicable tier. All NGP Follow-On Incentive Units that have not yet vested according to their applicable vesting requirements will automatically be forfeited and become null and void at the time a named executive officer's employment is terminated for any reason; provided, however, that, prior to such forfeiture, solely with respect to any unvested NGP Follow-On Incentive Units that are Tier I or Tier II units, the named executive officer will vest, immediately prior to his termination of employment, as to a pro rata amount of such unvested NGP Follow-On Incentive Units determined by multiplying the number of NGP Follow-On Incentive Units that would vest on the next annual vesting date by a fraction with a numerator equal to the number of full months that have elapsed since the most recent vesting date and a denominator of 12, with such pro rata amount rounded to the closest whole number. If a named executive officer's employment is terminated for "cause" (as defined below), or the named executive officer resigns or terminates the service relationship early (each, a "voluntary termination"), all vested NGP Follow-On Incentive Units will be forfeited at the time of the termination. In the event that a named executive officer's employment is terminated other than (i) for cause or (ii) due to a voluntary termination, the named executive officer will retain all vested NGP Follow-On Incentive Units following such termination. For purposes of the foregoing, a named executive officer's termination of employment means the termination of such named executive officer's employment with CRP, NGP Follow-On, CRD and all of its affiliates.

units entitle Tier V unitholders to 5% of future distributions, in each case, only after all of the members that have made capital contributions to NGP Follow-On have received cumulative cash distributions in respect of their membership interests equal to, for each tier, a certain factor times their cumulative capital contributions.

The consummation of the Business Combination resulted in a Fundamental Change with respect to the NGP Follow-On Incentive Units. Because neither the Company nor CRP is a party to the NGP Follow-On LLC Agreement, neither the Company nor CRP can be certain that the terms of the NGP Follow-On LLC Agreement will remain the same in the future.

Definitions. Under the CRD LLC Agreement and the NGP Follow-On LLC Agreement, a "Fundamental Change" is generally the occurrence of any of the following events: (i) (a) CRD merges or consolidates with or into, or enters into any similar transaction with, any person other than one of CRD's affiliates, members or certain of its other related parties; (b) CRD's outstanding interests are sold or exchanged in a single transaction, or a series of related transactions, to any person other than one of CRD's affiliates, members or certain of its other related parties; or (c) CRD sells, leases, licenses or exchanges, or agrees to sell, lease, license or exchange, all or substantially all of CRD's assets to a person that is not one of CRD's affiliates, members or certain of its other related parties, provided that in the case of any such transaction described in (a), (b) or (c), the individuals that served as members of CRD's board of managers before the consummation of such transaction cease to constitute at least a majority of the members of the board or analogous managing body of the surviving or acquiring entity immediately following completion of such transaction; (ii) any person or group (other than one of CRD's affiliates, members or certain of its other related parties) purchases or otherwise acquires the right to vote or dispose of securities of CRD representing 50% or more of the total voting power of all outstanding voting securities of CRD, unless the transaction was approved by CRD's board of managers; or (iii) CRD is dissolved and liquidated.

Under the CRD LLC Agreement and the NGP Follow-On LLC Agreement, a termination for "cause" generally occurs upon a named executive officer's: (i) conviction of, or plea of nolo contendere to, any felony or crime causing substantial harm to NGP Follow-On, CRD or their respective affiliates or involving acts of theft, fraud, embezzlement, moral turpitude, or similar conduct; (ii) repeated intoxication by alcohol or drugs during the performance of the named executive officer's duties in a manner that materially and adversely affects the performance of such duties; (iii) malfeasance in the conduct of the named executive officer's duties, including but not limited to (a) misuse or diversion of funds of NGP Follow-On, CRD or their respective affiliates, (b) embezzlement or (c) misrepresentations or concealments on any written reports submitted to NGP Follow-On, CRD or their respective affiliates; (iv) violation of the Voting and Transfer Restriction Agreement among CRD and its members or the named executive officer's confidentiality and noncompete agreement; or (v) failure to perform the duties of the named executive officer's employment relationship with CRP, NGP Follow-On, CRD or their respective affiliates, or failure to follow or comply with the reasonable and lawful written directives of CRP's board of directors, CRD's board of managers or the board of an affiliate of CRD or NGP Follow-On by which the named executive officer is employed with, in either case, after the named executive officer shall have been informed, in writing, of such failure and given a period of not less than 60 days to remedy the failure.

CRP's board of directors was formed in October 2014. No obligations with respect to compensation for directors have been accrued or paid for any periods prior to such formation date or following such formation date during the remainder of fiscal year 2014, fiscal year 2015 or through the Closing.

Compensation of Executive Officers and Directors after the Business Combination

After the completion of the Business Combination, on October 27, 2016, the Compensation Committee approved an annual base salary for Mark G. Papa and annual base salaries and annual target bonuses (expressed as a percentage of annual base salary) for our other current executive officers, as set forth in the following table:

Mr. Papa's annual bonus amount will be determined by our board of directors or the Compensation Committee in its discretion based on performance and other factors that our board of directors or the Compensation Committee determines are appropriate.

In connection with the Business Combination, our board of directors adopted and our stockholders approved the LTIP, which is described below under "—2016 Long Term Incentive Plan." On October 27, 2016, our Section 162(m) Plan Subcommittee granted Messrs. Papa, Glyphis and Smith options to purchase 1,000,000, 250,000 and 300,000 shares of our Class A Common Stock, respectively, under the LTIP at an exercise price per share of $14.52, which was the closing price of our Class A Common Stock on the date of grant. The options will vest and become exercisable in three substantially equal annual installments on each of the first three anniversaries of the date of grant, subject to the executive officer's continued service with us or our subsidiaries.

None of our executive officers is currently party to an employment agreement with us or has the right to receive severance payments or benefits upon a termination of employment. Mr. Papa is an advisor to Riverstone. We currently anticipate that Mr. Papa will spend approximately 60% of his working time providing services for us as our President and Chief Executive Officer and approximately 40% of his working time providing services to Riverstone on matters unrelated to the Company. The Compensation Committee and the Section 162(m) Plan Subcommittee were aware of Mr. Papa's continued service to Riverstone and considered it when determining an appropriate level of compensation for services as our President and Chief Executive Officer.

Directors employed by us or affiliated with Riverstone or Natural Gas Partners currently receive no compensation for serving on our board of directors or its committees. On October 27, 2016, our board of directors approved for each of Maire A. Baldwin, Jeffrey H. Tepper and Karl E. Bandtel an annual retainer of $87,500 per year in cash for service on our board of directors, payable quarterly in arrears and subject to proration for any partial year of service. In addition, our board of directors granted each of Ms. Baldwin and Messrs. Tepper and Bandtel, effective as of immediately following the effectiveness of a Registration Statement on Form S-8 covering the issuance of shares and other awards under the LTIP and subject to the director's continued service as a non-employee member of our board of directors through such effectiveness, 11,217 restricted shares of our Class A Common Stock under the LTIP, which will vest in a single installment on October 11, 2017. The board of directors anticipates that it will consider additional annual awards of restricted shares under our LTIP in the future that are intended to result in a total annual value of cash and equity-based compensation of $250,000 being paid to Ms. Baldwin and Messrs. Tepper and Bandtel for service on our board of directors.

In connection with the Business Combination, our board of directors adopted and our stockholders approved the LTIP, under which we may grant cash and equity-based incentive awards to eligible

service providers in order to attract, retain and motivate the persons who make important contributions to our company. The material terms of the LTIP are summarized below.

Our employees, consultants and directors, and employees and consultants of our subsidiaries, are eligible to receive awards under the LTIP. The LTIP is administered by our board of directors, which may delegate its duties and responsibilities to one or more committees of our directors and/or officers (referred to collectively as the "plan administrator"), subject to the limitations imposed under the LTIP, Section 16 of the Exchange Act, stock exchange rules and other applicable laws. On October 27, 2016, our board of directors delegated certain limited authority to our Chief Executive Officer to grant options and awards of restricted stock under the LTIP. The plan administrator has the authority to take all actions and make all determinations under the LTIP, to interpret the LTIP and award agreements and to adopt, amend and repeal rules for the administration of the LTIP as it deems advisable. The plan administrator also has the authority to determine which eligible service providers receive awards, grant awards and set the terms and conditions of all awards under the LTIP, including any vesting and vesting acceleration provisions, subject to the conditions and limitations in the LTIP.

An aggregate of 16,500,000 shares of Class A Common Stock have been reserved for issuance under the LTIP, all of which may be issued upon the exercise of incentive stock options. Shares issued under the LTIP may be authorized but unissued shares, shares purchased on the open market or treasury shares.

If an award under the LTIP expires, lapses or is terminated, exchanged for cash, surrendered, repurchased, canceled without having been fully exercised or forfeited, any unused shares subject to the award will again be available for new grants under the LTIP. Further, shares delivered to satisfy the purchase price or tax withholding obligation for any award other than an option or stock appreciation right will again be available for new grants under the LTIP. However, the LTIP does not allow the shares available for grant under the LTIP to be recharged or replenished with shares that:

Awards granted under the LTIP in substitution for any options or other stock or stock-based awards granted by an entity before the entity's merger or consolidation with us (or any of our subsidiaries) or our (or any of our subsidiary's) acquisition of the entity's property or stock will not reduce the shares available for grant under the LTIP, but will count against the maximum number of shares that may be issued upon the exercise of incentive stock options.

The maximum aggregate number of shares of Class A Common Stock with respect to which one or more awards of options or stock appreciation rights may be granted under the LTIP to any one person during any fiscal year is 1,000,000 shares of Class A Common Stock; and the maximum aggregate number of shares of Class A Common Stock with respect to which one or more awards of restricted stock, restricted stock units, or other stock or cash based awards that are denominated in shares

intended to qualify as performance-based compensation under Section 162(m) of the Code (as described below) may be granted under the LTIP to any one person during any fiscal year is 1,000,000 shares of Class A Common Stock. However, these numbers may be adjusted to take into account equity restructurings and certain other corporate transactions as described below. The maximum amount of cash that may be paid to any one person during any fiscal year with respect to one or more awards payable in cash and not denominated in shares is $5,000,000.

The LTIP provides for the grant of stock options, including incentive stock options ("ISOs") and nonqualified stock options ("NSOs"), stock appreciation rights ("SARs"), restricted stock, dividend equivalents, restricted stock units ("RSUs") and other stock or cash based awards. Certain awards under the LTIP may constitute or provide for payment of "nonqualified deferred compensation" under Section 409A of the Code. All awards under the LTIP will be set forth in award agreements, which will detail the terms and conditions of awards, including any applicable vesting and payment terms and post-termination exercise limitations. A brief description of each award type follows.

The plan administrator will determine whether specific performance awards are intended to constitute "qualified performance-based compensation" within the meaning of Section 162(m) of the Code and will have discretion to pay compensation that is not qualified performance-based compensation and that is not tax deductible. Under Section 162(m), a "covered employee" is our Chief Executive Officer and certain of our other most highly compensated executive officers. Section 162(m) imposes a $1 million cap on the compensation deduction that we may take in respect of compensation paid to covered employees; however, compensation that qualifies as qualified performance-based compensation is excluded from the calculation of the $1 million cap.

In order to constitute qualified performance-based compensation under Section 162(m), in addition to certain other requirements, the relevant amounts must be payable only upon the attainment of pre-established, objective performance goals set by the plan administrator and based on stockholder-approved performance criteria. Our stockholders have approved the below performance criteria.

For purposes of the LTIP, one or more of the following performance criteria will be used in setting performance goals applicable to qualified performance-based compensation, either for the entire company or a subsidiary, division, business unit or an individual, and may be used in setting performance goals applicable to other stock or cash based awards: net earnings or losses (either before or after one or more of interest, taxes, depreciation, amortization, and non-cash equity-based compensation expense); gross or net sales or revenue or sales or revenue growth; net income (either before or after taxes) or adjusted net income; profits (including but not limited to gross profits, net profits, profit growth, net operation profit or economic profit), profit return ratios or operating margin; budget or operating earnings (either before or after taxes or before or after allocation of corporate overhead and bonus); cash flow (including operating cash flow and free cash flow or cash flow return on capital); return on assets; return on capital or invested capital; cost of capital; return on stockholders' equity; total stockholder return; return on sales; costs, reductions in costs and cost control measures; expenses; working capital; earnings or loss per share; adjusted earnings or loss per share; price per share or dividends per share (or appreciation in or maintenance of such price or dividends); regulatory achievements or compliance; implementation, completion or attainment of objectives relating to research, development, regulatory, commercial, or strategic milestones or developments; market share; economic value or economic value added models; division, group or corporate financial goals; individual business objectives; production or growth in production; reserves or added reserves; growth in reserves per share; inventory growth; environmental, health and/or safety performance; effectiveness of hedging programs; improvements in internal controls and policies and procedures; customer satisfaction/growth; customer service; employee satisfaction; recruitment and maintenance of personnel; human resources management; supervision of litigation and other legal matters; strategic partnerships and transactions; financial ratios (including those measuring liquidity, activity, profitability or leverage); debt levels or reductions; sales-related goals; financing and other capital raising transactions; cash on hand; acquisition activity; investment sourcing activity; and marketing initiatives, any of which may be measured in absolute terms or as compared to any incremental increase or decrease. Such performance goals also may be based solely by reference to the company's performance or the performance of a

subsidiary, division, business segment or business unit of the company or a subsidiary, or based upon performance relative to performance of other companies or upon comparisons of any of the indicators of performance relative to performance of other companies. When determining performance goals, the plan administrator may provide for exclusion of the impact of an event or occurrence which the plan administrator determines should appropriately be excluded, including, without limitation, non-recurring charges or events, acquisitions or divestitures, changes in the corporate or capital structure, events unrelated to the business or outside of the control of management, foreign exchange considerations, and legal, regulatory, tax or accounting changes.

Under the LTIP, the plan administrator may not except in connection with equity restructurings and certain other corporate transactions as described below, without the approval of our stockholders, authorize the repricing of any outstanding option or SAR to reduce its price per share, or cancel any option or SAR in exchange for cash or another award when the price per share exceeds the Fair Market Value (as that term is defined in the LTIP) of the underlying shares.

In connection with certain corporate transactions and events affecting our Class A Common Stock, including a change in control, or change in any applicable laws or accounting principles, the plan administrator has broad discretion to take action under the LTIP to prevent the dilution or enlargement of intended benefits, facilitate the transaction or event or give effect to the change in applicable laws or accounting principles. This includes canceling awards for cash or property, accelerating the vesting of awards, providing for the assumption or substitution of awards by a successor entity, adjusting the number and type of shares subject to outstanding awards and/or with respect to which awards may be granted under the LTIP and replacing or terminating awards under the LTIP. In addition, in the event of certain non-reciprocal transactions with our stockholders, the plan administrator will make equitable adjustments to the LTIP and outstanding awards as it deems appropriate to reflect the transaction.

The LTIP provides that the plan administrator may establish compensation for non-employee directors from time to time subject to the LTIP's limitations. The plan administrator will from time to time determine the terms, conditions and amounts of all non-employee director compensation in its discretion and pursuant to the exercise of its business judgment, taking into account such factors, circumstances and considerations as it shall deem relevant from time to time, provided that the sum of any cash compensation or other compensation and the grant date fair value of any equity awards granted under the LTIP as compensation for services as a non-employee director during any fiscal year may not exceed $500,000. The plan administrator may make exceptions to this limit for individual non-employee directors in extraordinary circumstances, as the plan administrator may determine in its discretion, subject to the limitations in the LTIP.

Our board of directors may amend or terminate the LTIP at any time; however, no amendment, other than an amendment that increases the number of shares available under the LTIP, may materially and adversely affect an award outstanding under the LTIP without the consent of the affected participant and stockholder approval will be obtained for any amendment to the extent necessary to comply with applicable laws. The LTIP will remain in effect until the tenth anniversary of the date our board of directors adopted the LTIP, unless earlier terminated by our board of directors. No awards may be granted under the LTIP after its termination.

The plan administrator may modify awards granted to participants who are foreign nationals or employed outside the United States or establish subplans or procedures to address differences in laws, rules, regulations or customs of such foreign jurisdictions. All awards will be subject to any company claw-back policy as set forth in such claw-back policy or the applicable award agreement. Except as the plan administrator may determine or provide in an award agreement, awards under the LTIP are generally non-transferrable, except by will or the laws of descent and distribution, or, subject to the plan administrator's consent, pursuant to a domestic relations order, and are generally exercisable only by the participant. With regard to tax withholding obligations arising in connection with awards under the LTIP, and exercise price obligations arising in connection with the exercise of stock options under the LTIP, the plan administrator may, in its discretion, accept cash, wire transfer or check, shares of Class A Common Stock that meet specified conditions, a promissory note, a "market sell order," such other consideration as the plan administrator deems suitable or any combination of the foregoing.

On November 6, 2015, our Sponsor purchased 11,500,000 shares of Class B Common Stock, the founder shares, from us, for an aggregate purchase price of $25,000, or approximately $0.002 per share. In February 2016, our Sponsor transferred 40,000 founder shares to each of our then independent directors (together with our Sponsor, the "initial stockholders") at their original purchase price. On February 24, 2016, we effected a stock dividend of approximately 0.125 shares for each outstanding share of Class B Common Stock, resulting in the initial stockholders holding an aggregate of 12,937,500 founder shares. On April 8, 2016, following the expiration of the underwriters' remaining over-allotment option in connection with our IPO, our Sponsor forfeited 437,500 founder shares, so that the remaining 12,500,000 founder shares held by the initial stockholders would represent 20% of our then issued and outstanding shares of common stock. On October 11, 2016, all of the outstanding founder shares were automatically converted into shares of Class A Common Stock on a one-for-one basis in connection with the Closing.

The initial stockholders have agreed, subject to limited exceptions, not to transfer, assign or sell any of their shares of Class A Common Stock received upon conversion of their founder shares until the earlier to occur of: (A) one year after the completion of the Business Combination or (B) subsequent to the Business Combination, (x) if the last sale price of the Class A Common Stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and the like) for any 20 trading days within any 30 trading day period commencing at least 150 days after the Business Combination, or (y) the date on which we complete a liquidation, merger, stock exchange or other similar transaction that results in all of our stockholders having the right to exchange their shares of common stock for cash, securities or other property.

On February 29, 2016, our Sponsor purchased from us 8,000,000 Private Placement Warrants at a price of $1.50 per whole warrant ($12,000,000 in the aggregate) in a private placement that occurred simultaneously with the closing of our IPO. Each whole Private Placement Warrant is exercisable for one whole share of Class A Common Stock at a price of $11.50 per share. A portion of the purchase price of the Private Placement Warrants was placed in our trust account along with the proceeds from our IPO. The Private Placement Warrants are non-redeemable and exercisable on a cashless basis so long as they are held by our Sponsor or its permitted transferees.

Our Sponsor has agreed, subject to limited exceptions, not to transfer, assign or sell any of the Private Placement Warrants until 30 days after the completion of the Business Combination.

On November 6, 2015, our Sponsor agreed to loan us an aggregate of up to $300,000 to cover expenses related to our IPO pursuant to a promissory note (the "2015 Note"). The 2015 Note was non-interest bearing and payable on the earlier of March 31, 2016 or the completion of our IPO. On November 10, 2015, we borrowed $150,000 under the 2015 Note, and we borrowed the remaining $150,000 under the 2015 Note in February 2016. On February 29, 2016, the full $300,000 balance of the 2015 Note was repaid to our Sponsor.

On August 2, 2016, we issued an unsecured, non-interest bearing promissory note to our Sponsor (the "2016 Note"). We borrowed $300,000 under the 2016 Note, and repaid the full $300,000 balance on the Closing Date.

In connection with the closing of the Business Combination, we and the Centennial Contributors entered into CRP's fifth amended and restated limited liability company agreement (the "A&R LLC Agreement"). The operations of CRP, and the rights and obligations of the holders of CRP Common Units, are set forth in the A&R LLC Agreement.

Appointment as Manager. Under the A&R LLC Agreement, we are a member and the sole manager of CRP. As the sole manager, we are able to control all of the day-to-day business affairs and decision-making of CRP without the approval of any other member, unless otherwise stated in the A&R LLC Agreement. As such, we, through our officers and directors, are responsible for all operational and administrative decisions of CRP and the day-to-day management of CRP's business. Pursuant to the terms of the A&R LLC Agreement, we cannot, under any circumstances, be removed as the sole manager of CRP except by our election.

Compensation. We are not entitled to compensation for our services as manager. We are entitled to reimbursement by CRP for any reasonable out-of-pocket expenses incurred on behalf of CRP, including all of our fees, expenses and costs of being a public company (including public reporting obligations, proxy statements, stockholder meetings, stock exchange fees, transfer agent fees, SEC and FINRA filing fees and offering expenses) and maintaining our corporate existence.

Recapitalization. The A&R LLC Agreement provides for the exchange of all outstanding membership interests of CRP held by the Centennial Contributors prior to the closing of the Business Combination for newly issued CRP Common Units at the closing. Each CRP Common Unit entitles the holder to a pro rata share of the net profits and net losses and distributions of CRP.

Distributions. The A&R LLC Agreement allows for distributions to be made by CRP to its members on a pro rata basis out of "distributable cash" (as defined in the A&R LLC Agreement). We expect CRP may make distributions out of distributable cash periodically to the extent permitted by the debt agreements of CRP and necessary to enable us to cover our operating expenses and other obligations, as well as to make dividend payments, if any, to the holders of our Class A Common Stock. In addition, the A&R LLC Agreement generally requires CRP to make pro rata distributions to its members, including us, in an amount at least sufficient to allow us to pay our taxes.

CRP Common Unit Redemption Right. The A&R LLC Agreement provides a redemption right to the Centennial Contributors which entitles them to cause CRP to redeem, from time to time, all or a portion of their CRP Common Units for, at CRP's option, newly-issued shares of our Class A Common Stock on a one-for-one basis or a cash payment equal to the average of the volume-weighted closing price of one share of Class A Common Stock for the five trading days prior to the date the Centennial Contributors deliver a notice of redemption for each CRP Common Unit redeemed (subject to customary adjustments, including for stock splits, stock dividends and reclassifications). In the event of a "reclassification event" (as defined in the A&R LLC Agreement), the manager is to ensure that each CRP Common Unit is redeemable for the same amount and type of property, securities or cash that a share of Class A Common Stock becomes exchangeable for or converted into as a result of such "reclassification event." Upon the exercise of the redemption right, the Centennial Contributor will surrender its CRP Common Units to CRP for cancellation. The A&R LLC Agreement requires that we contribute cash or shares of our Class A Common Stock to CRP in exchange for a number of CRP Common Units in CRP equal to the number of CRP Common Units to be redeemed from the Centennial Contributor. CRP will then distribute such cash or shares of our Class A Common Stock to such Centennial Contributor to complete the redemption. Upon the exercise of the redemption right, we may, at our option, effect a direct exchange of cash or our Class A Common Stock for such CRP Common Units in lieu of such a redemption. Upon the 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.

Change of Control. In connection with the occurrence of a "manager change of control" (as defined below), we have the right to require each member of CRP (other than us) to cause CRP to redeem some or all of such member's CRP Common Units and a corresponding number of shares of Class C Common Stock, in each case, effective immediately prior to the consummation of the manager change of control. From and after the date of such redemption, the CRP Common Units and shares of Class C Common Stock subject to such redemption will be deemed to be transferred to us and each such member will cease to have any rights with respect to the CRP Common Units and shares of Class C Common Stock subject to such redemption (other than the right to receive shares of Class A Common Stock pursuant to such redemption). A "manager change of control" will be deemed to have occurred if or upon: (i) the consummation of a sale, lease or transfer of all or substantially all of our assets (determined on a consolidated basis) to any person or "group" (as such term is used in Section 13(d)(3)) that has been approved by our stockholders and board of directors, (ii) a merger or consolidation of the Company with any other person (other than a transaction in which our voting securities outstanding immediately prior to the transaction continue to represent at least 50.01% of our or the surviving entity's total voting securities following the transaction) that has been approved by our stockholders and board of directors or (iii) subject to certain exceptions, the acquisition by any person or "group" (as such term is used in Section 13(d)(3)) of beneficial ownership of at least 50.01% of our voting securities, if recommended or approved by our board of directors or determined by our board of directors to be in our and our stockholders' best interests.

Maintenance of One-to-One Ratios. The A&R LLC Agreement includes provisions intended to ensure that we at all times maintain a one-to-one ratio between (a) the number of outstanding shares of Class A Common Stock and the number of CRP Common Units owned by us (subject to certain exceptions for certain rights to purchase our equity securities under a "poison pill" or similar shareholder rights plan, if any, certain convertible or exchangeable securities issued under our equity compensation plans and certain equity securities issued pursuant to our equity compensation plans (other than a stock option plan) that are restricted or have not vested thereunder) and (b) the number of outstanding shares of our Class C Common Stock and the number of CRP Common Units owned by the Centennial Contributors. This construct is intended to result in the Centennial Contributors having a voting interest in the Company that is identical to the Centennial Contributors' economic interest in CRP.

Transfer Restrictions. The A&R LLC Agreement generally does not permit transfers of CRP Common Units by members, subject to limited exceptions. Any transferee of CRP Common Units must assume, by operation of law or written agreement, all of the obligations of a transferring member with respect to the transferred units, even if the transferee is not admitted as a member of CRP.

Dissolution. The A&R LLC Agreement provides that the unanimous consent of all members will be required to voluntarily dissolve CRP. In addition to a voluntary dissolution, CRP will be dissolved upon a change of control transaction under certain circumstances, as well as upon the entry of a decree of judicial dissolution or other circumstances in accordance with Delaware law. Upon a dissolution event, the proceeds of a liquidation will be distributed in the following order: (i) first, to pay the expenses of winding up CRP; (ii) second, to pay debts and liabilities owed to creditors of CRP; and (iii) third, to the members pro-rata in accordance with their respective percentage ownership interests in CRP (as determined based on the number of CRP Common Units held by a member relative to the aggregate number of all outstanding CRP Common Units).

Confidentiality. Each member has agreed to maintain the confidentiality of CRP's confidential information. This obligation excludes information independently obtained or developed by the members, information that is in the public domain or otherwise disclosed to a member, in either such

case not in violation of a confidentiality obligation or disclosures required by law or judicial process or approved by our chief executive officer.

Indemnification and Exculpation. The A&R LLC Agreement provides for indemnification of the manager, members and officers of CRP and their respective subsidiaries or affiliates and provides that, except as otherwise provided therein, we, as the managing member of CRP, have the same fiduciary duties to CRP and its members as are owed to a corporation organized under Delaware law and its stockholders by its directors.

In connection with the Closing, on October 11, 2016, the Company entered into an amended and restated registration rights agreement (the "Registration Rights Agreement") with our Sponsor, certain of our former and current directors, Riverstone Centennial Holdings, L.P. (the "Riverstone private investor") and the Centennial Contributors, pursuant to which such parties are entitled to certain registration rights relating to (i) shares of our Class A Common Stock issued to our Sponsor and such former and current directors upon the conversion of their founder shares at the Closing, (ii) the Private Placement Warrants and warrants that may be issued upon conversion of working capital loans (and any shares of Class A Common Stock issuable upon the exercise of such warrants), (iii) the Centennial Holder Shares and (iv) the Shares of Class A Common Stock issued to the Riverstone private investor (collectively, the "Registrable Securities").

The holders of a majority of the Registrable Securities (other than the Centennial Holder Shares and the shares of Class A Common Stock held by the Riverstone private investor) are entitled to make up to three demands, excluding short form demands, that we register the resale of such securities, while holders of a majority of the Registrable Securities owned by the Riverstone private investor and its permitted transferees are entitled to five demands, excluding short form demands, that we register the resale of such securities. Under the Registration Rights Agreement, we are required to, within 30 calendar days after consummation of the Transactions, file the registration statement of which this prospectus forms a part registering the resale of the Centennial Holder Shares. Additionally, the holders of a majority of the Centennial Holder Shares are entitled to demand one underwritten offering if the offering is reasonably expected to result in gross proceeds of more than $50 million.

The holders also have certain "piggy-back" registration rights with respect to registration statements and rights to require us to register for resale such securities pursuant to Rule 415 under the Securities Act. However, the Registration Rights Agreement provides that we will not permit any registration statement filed under the Securities Act with respect to the founder shares and the Private Placement Warrants and the shares of Class A Common Stock underlying such Private Placement Warrants to become effective until termination of the applicable lock-up period, which occurs (i) in the case of the founder shares, on the earlier of (A) October 11, 2017, (B) if the last sale price of our Class A Common Stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar transactions) for any 20 trading days within any 30-trading day period commencing at least 150 days after the Closing Date, or (C) the date on which we complete a liquidation, merger, capital stock exchange, reorganization or other similar transaction that results in all of our stockholders having the right to exchange their shares of common stock for cash, securities or other property and (ii) in the case of the Private Placement Warrants and the shares of Class A Common Stock underlying such Private Placement Warrants, November 11, 2016. We will bear the expenses incurred in connection with the filing of any such registration statements.

In connection with the Business Combination, on July 21, 2016, we entered into subscription agreements (the "Investor Subscription Agreements") with certain accredited investors pursuant to

which such investors purchased, in the aggregate, 20,000,000 shares of Class A Common Stock at the Closing for an aggregate purchase price of $200 million.

On the same date, the Company entered into a separate subscription agreement (the "Riverstone Subscription Agreement" and, together with the Investor Subscription Agreements, the "Subscription Agreements"), with the Riverstone private investor, pursuant to which the Riverstone private investor purchased 81,005,000 shares of Class A Common Stock at the Closing for an aggregate purchase price of approximately $810 million.

Pursuant to the Riverstone Subscription Agreement, the Riverstone private investor also agreed to be ready, willing and able to purchase additional shares of Class A Common Stock at $10.00 per share in an amount such that the proceeds therefrom, together with certain other available funds, would be sufficient for the Company to pay the cash consideration in the Business Combination, repay certain outstanding indebtedness of CRP, offset any redemptions of Class A Common Stock in connection with the Transactions and pay transaction-related expenses incurred by the Company. No redemptions of Class A Common Stock were made in connection with the Closing and, therefore, no additional shares of Class A Common Stock were purchased.

Prior to the closing of our IPO, we did not have a formal policy for the review, approval or ratification of related party transactions. Accordingly, certain of the transactions discussed above were not reviewed, approved or ratified in accordance with any such policy.

We have adopted a code of ethics requiring us to avoid, wherever possible, all conflicts of interests, except under guidelines or resolutions approved by our board of directors (or the appropriate committee of our board) or as disclosed in our public filings with the SEC. Under our code of ethics, conflict of interest situations include any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) involving the company. A copy of our code of ethics is available on our website.

In addition, our Audit Committee, pursuant to its charter, is responsible for reviewing and approving related party transactions to the extent that we enter into such transactions. An affirmative vote of a majority of the members of the Audit Committee present at a meeting at which a quorum is present is required in order to approve a related party transaction. A majority of the members of the entire Audit Committee will constitute a quorum. Without a meeting, the unanimous written consent of all of the members of the Audit Committee will be required to approve a related party transaction. A copy of the Audit Committee charter is available on our website. We also require each of our directors and executive officers to complete a directors' and officers' questionnaire that elicits information about related party transactions.

These procedures are intended to determine whether any such related party transaction impairs the independence of a director or presents a conflict of interest on the part of a director, employee or officer.

Our Audit Committee will review on a quarterly basis any payments that are made to our Sponsor, officers or directors, or our or their affiliates.

The following table sets forth information known to us regarding ownership of shares of our voting common stock as of November 15, 2016:

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 is based on 183,505,000 shares of voting common stock issued and outstanding in the aggregate as of November 15, 2016.

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.

Name and Address of Beneficial Owners

*5% or Greater Stockholders*
Riverstone Centennial Holdings, L.P.(1)	81,005,000	44.1	%
Silver Run Sponsor, LLC(2)	12,380,000	6.7	%
Centennial Resource Development, LLC(3)	12,227,062	6.7	%
Celero Energy Company, LP(4)	4,246,898	2.3	%
NGP Centennial Follow-On LLC(5)	2,681,961	1.7	%
Funds advised by Capital Research and Management Company(6)	10,706,400	5.8	%
Fidelity Contrafund: Fidelity Advisor Series Opportunistic Insights Fund(7)(8)	40,200	*
Fidelity Contrafund: Fidelity Contrafund(7)(8)	5,188,000	2.8	%
Fidelity Contrafund Commingled Pool(7)	512,900	*
Fidelity Contrafund: Fidelity Advisor New Insights Fund(7)(8)	1,224,500	*
Fidelity Contrafund: Fidelity Series Opportunistic Insights Fund(7)(8)	278,900	*
Variable Insurance Products Fund III: Balanced Portfolio(7)(8)	148,900	*
Fidelity Puritan Trust: Fidelity Balanced Fund(7)(8)	1,365,900	*
Variable Insurance Products Fund II: Contrafund Portfolio(7)(8)	872,100	*
Fidelity Advisor Series I: Fidelity Advisor Balanced Fund(7)(8)	110,100	*
Fidelity Select Portfolios: Energy Portfolio(7)(8)	115,200	*
Variable Insurance Products Fund IV: Energy Portfolio(7)(8)	14,400	*
Fidelity Central Investment Portfolios LLC: Fidelity Energy Central Fund(7)(8)	45,400	*
Fidelity Advisor Series VII: Fidelity Advisor Energy Fund(7)(8)	45,200	*
Fidelity Select Portfolios: Natural Resources Portfolio(7)(8)	38,300	*
*Directors and Executive Officers*
Mark G. Papa	10,000	*
George S. Glyphis	—	—
Sean R. Smith	—	—
Jeffrey H. Tepper	40,000	*
Tony R. Weber	—	—
Robert M. Tichio	—	—
David M. Leuschen	—	—
Pierre F. Lapeyre Jr.	—	—
Maire A. Baldwin	—	—
Karl E. Bandtel	—	—
All directors and executive officers, as a group (10 individuals)	50,000	*

securities owned of record by Riverstone Centennial Holdings, L.P. Each such entity or person disclaims any such beneficial ownership of such securities. The business address for each of the persons named in this footnote is c/o Riverstone Holdings, 712 Fifth Avenue, 36th Floor, New York, NY 10019.

(2): Silver Run Sponsor, LLC is the record holder of these securities. Silver Run Sponsor Manager, LLC is the managing member of Silver Run Sponsor, LLC. Riverstone Holdings LLC is the managing member of Silver Run Sponsor Manager, LLC. Pierre F. Lapeyre, Jr. and David M. Leuschen are the managing directors of Riverstone Holdings LLC and have or share voting and investment discretion with respect to the securities held of record by Silver Run Sponsor, 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, LLC 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.
(3): 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.
(4): 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 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.

(5): 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.
(6): Includes 5,975,700 shares of Class A Common Stock held by SMALLCAP World Fund, Inc. ("SCWF") and 4,730,700 shares of Class A Common Stock held by The Growth Fund of America ("GFA," and, together with SCWF, 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. 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.

(7): 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.
(8): 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.

The selling stockholders may offer and sell, from time to time, any or all of the shares of Class A Common Stock being offered for resale by this prospectus, which includes 101,005,000 Private Placement Shares and 20,000,000 Centennial Holder Shares. The term "selling stockholders" includes the stockholders listed in the table below and their permitted transferees. The Private Placement Shares and Centennial Holder Shares are being registered by the registration statement of which this prospectus forms a part pursuant to the Registration Rights Agreement entered into in connection with the Business Combination.

The following table provides, as of November 15, 2016, information regarding the beneficial ownership of our Class A Common Stock and Class C Common Stock held by each selling stockholder, the number of shares of Class A Common Stock that may be sold by each selling stockholder under this prospectus and that each selling stockholder will beneficially own after this offering.

Because each selling stockholder may dispose of all, none or some portion of their securities, no estimate can be given as to the number of securities that will be beneficially owned by a selling stockholder upon termination of this offering. For purposes of the table below, however, we have assumed that after termination of this offering none of the securities covered by this prospectus will be beneficially owned by the selling stockholders and further assumed that the selling stockholders will not acquire beneficial ownership of any additional securities during the offering. In addition, the selling stockholders may have sold, transferred or otherwise disposed of, or may sell, transfer or otherwise dispose of, at any time and from time to time, our securities in transactions exempt from the registration requirements of the Securities Act after the date on which the information in the table is presented.

We may amend or supplement this prospectus from time to time in the future to update or change this selling stockholders list and the securities that may be resold.

Please see the section entitled "Plan of Distribution" for further information regarding the stockholders' method of distributing these shares.

	Number of Shares of Common Stock Owned Prior to Offering

	Number of Shares of Common Stock Owned Prior to Offering					Number of Shares of Class A Common Stock Owned After Offering
Name of Selling Stockholder	Class A Common Stock		Class C Common Stock
Riverstone Centennial Holdings, L.P.		81,005,000		—	81,005,000		—
Centennial Resource Development, LLC(1)		—		12,227,062	12,227,062		—
Celero Energy Company, LP(1)		—		4,246,898	4,246,898		—
NGP Centennial Follow-On LLC(1)		—		2,681,961	2,681,961		—
CP VI-A Centennial, L.P.		844,079		—	844,079		—
Funds advised by Capital Research and Management Company		10,706,400		—	10,706,400		—
Fidelity Contrafund: Fidelity Advisor Series Opportunistic Insights Fund		40,200		—	40,200		—
Fidelity Contrafund: Fidelity Contrafund		5,188,000		—	5,188,000		—
Fidelity Contrafund Commingled Pool		512,900		—	512,900		—
Fidelity Contrafund: Fidelity Advisor New Insights Fund		1,224,500		—	1,224,500		—
Fidelity Contrafund: Fidelity Series Opportunistic Insights Fund		278,900		—	278,900		—
Variable Insurance Products Fund III: Balanced Portfolio		148,900		—	148,900		—
Fidelity Puritan Trust: Fidelity Balanced Fund		1,365,900		—	1,365,900		—
Variable Insurance Products Fund II: Contrafund Portfolio		872,100		—	872,100		—
Fidelity Advisor Series I: Fidelity Advisor Balanced Fund		110,100		—	110,100		—
Fidelity Select Portfolios: Energy Portfolio		115,200		—	115,200		—
Variable Insurance Products Fund IV: Energy Portfolio		14,400		—	14,400		—
Fidelity Central Investment Portfolios LLC: Fidelity Energy Central Fund		45,400		—	45,400		—
Fidelity Advisor Series VII: Fidelity Advisor Energy Fund		45,200		—	45,200		—
Fidelity Select Portfolios: Natural Resources Portfolio		38,300		—	38,300		—

Please see "Certain Relationships and Related Transactions" appearing elsewhere in this prospectus for information regarding material relationships with our selling stockholders within the past three years.

We are registering the issuance of shares of Class A Common Stock underlying the Public Warrants. The prices at which the shares of Class A Common Stock underlying the Public Warrants covered by this prospectus may actually be disposed of may be at fixed prices, at prevailing market prices at the time of sale, at prices related to the prevailing market price, at varying prices determined at the time of sale or at negotiated prices. We will receive the proceeds from the exercise of the Public Warrants, but not from the sale of the underlying Class A Common Stock.

Pursuant to the terms of the Public Warrants, the shares of Class A Common Stock will be distributed to those Public Warrant holders who surrender the certificates representing the Public Warrants and provide payment of the exercise price through their brokers to our warrant agent, Continental Stock Transfer & Trust Company.

We are also registering the resale of shares of Class A Common Stock by the selling stockholders named herein. The selling stockholders, which as used herein includes their permitted transferees, may, from time to time, sell, transfer or otherwise dispose of any or all of their shares on NASDAQ or any other stock exchange, market or trading facility on which such shares are traded or in private transactions. These dispositions may be at fixed prices, at prevailing market prices at the time of sale, at prices related to the prevailing market price, at varying prices determined at the time of sale or at negotiated prices.

The selling stockholders may use any one or more of the following methods when disposing of their shares of Class A Common Stock:

The selling stockholders may, from time to time, pledge or grant a security interest in some or all of the shares of Class A Common Stock owned by them and, if they default in the performance of their secured obligations, the pledgees or secured parties may offer and sell their shares, from time to time, under this prospectus, or under an amendment to this prospectus under Rule 424(b)(3) or other

applicable provision of the Securities Act amending the list of selling stockholders to include the pledgee, transferee or other successors in interest as selling stockholders under this prospectus. The selling stockholders also may transfer their shares in other circumstances, in which case the transferees, pledgees or other successors in interest will be the selling beneficial owners for purposes of this prospectus.

In connection with the sale of our Class A Common Stock or interests therein, the selling stockholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in turn engage in short sales of our securities in the course of hedging the positions they assume. The selling stockholders may also sell their securities short and deliver these securities to close out their short positions, or loan or pledge such securities to broker-dealers that in turn may sell these securities. The selling stockholders may also enter into option or other transactions with broker-dealers or other financial institutions or the creation of one or more derivative securities which require the delivery to such broker-dealer or other financial institution of the shares offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).

The aggregate proceeds to the selling stockholders from the sale of the shares offered by them will be the purchase price of the share less discounts or commissions, if any. Each of the selling stockholders reserves the right to accept and, together with their agents from time to time, to reject, in whole or in part, any proposed purchase of their shares to be made directly or through agents. We will not receive any of the proceeds from the resale of shares of Class A Common Stock being offered by the selling stockholders named herein.

The selling stockholders also may resell all or a portion of their shares in open market transactions in reliance upon Rule 144 under the Securities Act, provided that they meet the criteria and conform to the requirements of that rule.

In connection with an underwritten offering, underwriters or agents may receive compensation in the form of discounts, concessions or commissions from the selling stockholders or from purchasers of the offered shares for whom they may act as agents. In addition, underwriters may sell the shares to or through dealers, and those dealers may receive compensation in the form of discounts, concessions or commissions from the underwriters and/or commissions from the purchasers for whom they may act as agents. The selling stockholders and any underwriters, dealers or agents participating in a distribution of the shares may be deemed to be "underwriters" within the meaning of the Securities Act, and any profit on the sale of the shares by the selling stockholders and any commissions received by broker-dealers may be deemed to be underwriting commissions under the Securities Act.

To the extent required, the shares of Class A Common Stock to be sold, the names of the selling stockholders, the respective purchase prices and public offering prices, the names of any agent, dealer or underwriter, and any applicable commissions or discounts with respect to a particular offer will be set forth in an accompanying prospectus supplement or, if appropriate, a post-effective amendment to the registration statement that includes this prospectus.

In order to comply with the securities laws of some states, if applicable, our shares of Class A Common Stock may be sold in these jurisdictions only through registered or licensed brokers or dealers. In addition, in some states our shares of Class A Common Stock may not be sold unless they have been registered or qualified for sale or an exemption from registration or qualification requirements is available and is complied with.

If a selling stockholder wants to sell its shares of Class A Common Stock under this prospectus in the United States, the selling stockholders will also need to comply with state securities laws, also

known as "Blue Sky laws," with regard to secondary sales. All states offer a variety of exemption from registration for secondary sales. Many states, for example, have an exemption for secondary trading of securities registered under Section 12(g) of the Exchange Act or for securities of issuers that publish continuous disclosure of financial and non-financial information in a recognized securities manual, such as Standard & Poor's. The broker for a selling stockholder will be able to advise a selling stockholder in which states shares of Class A Common Stock are exempt from registration for secondary sales.

Any person who purchases shares of Class A Common Stock from a selling stockholder offered by this prospectus who then wants to sell such shares will also have to comply with Blue Sky laws regarding secondary sales.

When the registration statement that includes this prospectus becomes effective, and a selling stockholder indicates in which state(s) he desires to sell his shares of Class A Common Stock we will be able to identify whether it will need to register or will rely on an exemption there from.

We have advised the selling stockholders that the anti-manipulation rules of Regulation M under the Exchange Act may apply to sales of securities in the market and to the activities of the selling stockholders and their affiliates. In addition, we will make copies of this prospectus (as it may be supplemented or amended from time to time) available to the selling stockholders for the purpose of satisfying the prospectus delivery requirements of the Securities Act. The selling stockholders may indemnify any broker-dealer that participates in transactions involving the sale of their shares against certain liabilities, including liabilities arising under the Securities Act.

We have agreed to indemnify, to the extent permitted by law, the selling stockholders (and each selling stockholder's officers and directors and each person who controls such selling stockholder) against liabilities caused by any untrue or alleged untrue statement of material fact contained in this prospectus or the registration statement of which this prospectus forms a part (including any amendment or supplement thereof) or any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein not misleading, except insofar as the same are caused by or contained in any information furnished in writing to the Company by such selling stockholder expressly for use herein. We have also agreed with the Riverstone private investor and the Centennial Contributors to keep the registration statement of which this prospectus forms a part effective until the earlier of (i) the date on which all of their shares are disposed of pursuant to this prospectus; (ii) such shares shall have been otherwise transferred, new certificates for such shares not bearing a legend restricting further transfer shall have been delivered by the Company and subsequent public distribution of such shares shall not require registration under the Securities Act; (iii) such shares shall have ceased to be outstanding; or (iv) such shares have been sold without registration pursuant to Rule 144 promulgated under the Securities Act.

We are required to pay all fees and expenses incident to the registration of the shares of Class A Common Stock covered by this prospectus, including with regard to compliance with state securities or Blue Sky laws. Otherwise, all discounts, commissions or fees incurred in connection with the sale of shares of Class A Common Stock offered hereby will be paid by the selling stockholders.

The Company has authorized 641,000,000 shares of capital stock, consisting of (a) 640,000,000 shares of common stock, including (i) 600,000,000 shares of Class A Common Stock, (ii) 20,000,000 shares of Class B Common Stock and (iii) 20,000,000 shares of Class C Common Stock and (b) 1,000,000 shares of preferred stock, including one share of Series A Preferred Stock. As of November 15, 2016, there were: (a) 23 holders of record of Class A Common Stock and 164,349,079 shares of Class A Common Stock outstanding; (b) no holders of record of Class B Common Stock and no shares of Class B Common Stock outstanding; (c) three holders of record of Class C Common Stock and 19,155,921 shares of Class C Common Stock outstanding; (d) one holder of record of Series A Preferred Stock and one share of Series A Preferred Stock outstanding; (e) one holder of the Public Warrants and 16,666,643 Public Warrants outstanding; and (f) one holder of the Private Placement Warrants and 8,000,000 Private Placement Warrants outstanding.

Holders of the Company's Class A Common Stock are entitled to one vote for each share held on all matters to be voted on by the Company's stockholders. Holders of the Class A Common Stock and holders of the Class C Common Stock will vote together as a single class on all matters submitted to a vote of the Company's stockholders, except as required by law. Unless specified in the Company's second amended and restated charter (the "Charter") (including any certificate of designation of preferred stock) or amended and restated bylaws (the "Bylaws"), or as required by applicable provisions of the Delaware General Corporation Law or applicable stock exchange rules, the affirmative vote of a majority of the Company's shares of common stock that are voted is required to approve any such matter voted on by the Company's stockholders. There is no cumulative voting with respect to the election of directors, with the result that the holders of more than 50% of the shares voted for the election of directors can elect all of the directors (subject to the right of the holder of our Series A Preferred Stock to nominate and elect one director). Subject to the rights of the holders of any outstanding series of preferred stock, the Company's stockholders are entitled to receive ratable dividends when, as and if declared by the board of directors out of funds legally available therefor.

In the event of a liquidation, dissolution or winding up of the Company, the holders of the Class A Common Stock are entitled to share ratably in all assets remaining available for distribution to them after payment of liabilities and after provision is made for each class of stock, if any, having preference over the Class A Common Stock. The Company's stockholders have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the Class A Common Stock.

In connection with the Business Combination, we issued 20,000,000 shares of Class C Common Stock to the Centennial Contributors. Holders of Class C Common Stock, together with holders of Class A Common Stock voting as a single class, will have the right to vote on all matters properly submitted to a vote of the stockholders. In addition, the holders of Class C Common Stock, voting as a separate class, will be entitled to approve any amendment, alteration or repeal of any provision of our Charter that would alter or change the powers, preferences or relative, participating, optional or other or special rights of the Class C Common Stock. Holders of Class C Common Stock will not be entitled to any dividends from the Company and will not be entitled to receive any of our assets in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.

Shares of Class C Common Stock may be issued only to the Centennial Contributors, their respective successors and assigns, as well as any permitted transferees of the Centennial Contributors. A holder of Class C Common Stock may transfer shares of Class C Common Stock to any transferee (other than the Company) only if such holder also simultaneously transfers an equal number of such

holder's CRP Common Units to such transferee in compliance with the amended and restated limited liability company agreement of CRP. The Centennial Contributors generally have the right to cause CRP to redeem all or a portion of their CRP Common Units in exchange for shares of the Company's Class A Common Stock or, at CRP's option, an equivalent amount of cash. The Company may, however, at its option, effect a direct exchange of cash or Class A Common Stock for such CRP Common Units in lieu of such a redemption by CRP. Upon the future redemption or exchange of CRP Common Units held by a Centennial Contributor, a corresponding number of shares of Class C Common Stock will be canceled.

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

Each whole Public Warrant issued in our IPO entitles the registered holder to purchase one whole share of our Class A Common Stock at a price of $11.50 per share, subject to adjustment as discussed below, at any time commencing 12 months from the closing of our IPO. Pursuant to the warrant agreement, a warrant holder may exercise its Public Warrants only for a whole number of shares of Class A Common Stock. No fractional Public Warrants have been issued and only whole Public Warrants trade. The Public Warrants will expire five years after the Closing Date, at 5:00 p.m., New York City time, or earlier upon redemption or liquidation.

The Company will not be obligated to deliver any shares of Class A Common Stock pursuant to the exercise of a Public Warrant and will have no obligation to settle exercise unless the registration statement of which this prospectus forms a part is then effective and a prospectus relating thereto is current, subject to the Company satisfying its obligations described below with respect to registration. No Public Warrant will be exercisable and the Company will not be obligated to issue shares of Class A Common Stock upon exercise of a Public Warrant unless Class A Common Stock issuable upon such exercise has been registered, qualified or deemed to be exempt under the securities laws of the state of residence of the registered holder of the Public Warrants. In the event that the conditions in the two immediately preceding sentences are not satisfied with respect to a Public Warrant, the holder of such Public Warrant will not be entitled to exercise such Public Warrant and such Public Warrant may have no value and expire worthless.

Under the warrant agreement, the Company agreed that as soon as practicable, but in no event later than 15 business days, after the closing of the Business Combination, the Company would use its best efforts to file with the SEC the registration statement of which this prospectus forms a part, for the registration, under the Securities Act, of the shares of Class A Common Stock issuable upon exercise of the Public Warrants. We have agreed to use our best efforts to cause the same to become

effective and to maintain the effectiveness of such registration statement, and a current prospectus relating thereto, until the expiration of the Public Warrants in accordance with the provisions of the warrant agreement. Notwithstanding the above, if the Class A Common Stock is at the time of any exercise of a Public Warrant not listed on a national securities exchange such that it satisfies the definition of a "covered security" under Section 18 (b)(1) of the Securities Act, the Company may, at its option, require holders of Public Warrants who exercise their Public Warrants to do so on a "cashless basis" in accordance with Section 3(a)(9) of the Securities Act and, in the event the Company so elects, it will not be required to file or maintain in effect a registration statement, but the Company will be required to use its best efforts to register or qualify the shares under applicable blue sky laws to the extent an exemption is not available.

Once the Public Warrants become exercisable, the Company may call the Public Warrants for redemption:

If and when the Public Warrants become redeemable by the Company, the Company may exercise its redemption right even if it is unable to register or qualify the underlying securities for sale under all applicable state securities laws.

The Company has established the last of the redemption criterion discussed above to prevent a redemption call unless there is at the time of the call a significant premium to the Public Warrant exercise price. If the foregoing conditions are satisfied and the Company issues a notice of redemption of the Public Warrants, each Public Warrant holder will be entitled to exercise its Public Warrant prior to the scheduled redemption date. However, the price of the Class A Common Stock may fall below the $18.00 redemption trigger price as well as the $11.50 Public Warrant exercise price after the redemption notice is issued.

If the Company calls the Public Warrants for redemption as described above, the Company's management will have the option to require any holder that wishes to exercise its Public Warrant to do so on a "cashless basis." In determining whether to require all holders to exercise their Public Warrants on a "cashless basis," the Company's management will consider, among other factors, its cash position, the number of Public Warrants that are outstanding and the dilutive effect on its stockholders of issuing the maximum number of shares of Class A Common Stock issuable upon the exercise of its Public Warrants. If the Company's management takes advantage of this option, all holders of Public Warrants would pay the exercise price by surrendering their Public Warrants for that number of shares of Class A Common Stock equal to the quotient obtained by dividing (x) the product of the number of shares of Class A Common Stock underlying the Public Warrants, multiplied by the difference between the exercise price of the Public Warrants and the "fair market value" (defined below) by (y) the fair market value. The "fair market value" shall mean the average reported last sale price of the Class A Common Stock for the 10 trading days ending on the third trading day prior to the date on which the notice of redemption is sent to the holders of Public Warrants. If the Company's management takes advantage of this option, the notice of redemption will contain the information necessary to calculate the number of shares of Class A Common Stock to be received upon exercise of the Public Warrants, including the "fair market value" in such case. Requiring a cashless exercise in this manner will reduce the number of shares to be issued and thereby lessen the dilutive effect of a Public Warrant

redemption. The Company believes this feature is an attractive option to the Company if it does not need the cash from the exercise of the Public Warrants. If the Company calls its Public Warrants for redemption and its management does not take advantage of this option, our Sponsor and its permitted transferees would still be entitled to exercise their Private Placement Warrants for cash or on a cashless basis using the same formula described above that other Public Warrant holders would have been required to use had all Public Warrant holders been required to exercise their Public Warrants on a cashless basis, as described in more detail below.

A holder of a Public Warrant may notify the Company in writing in the event it elects to be subject to a requirement that such holder will not have the right to exercise such Public Warrant, to the extent that after giving effect to such exercise, such person (together with such person's affiliates), to the warrant agent's actual knowledge, would beneficially own in excess of 9.8% (or such other amount as a holder may specify) of the shares of Class A Common Stock outstanding immediately after giving effect to such exercise.

If the number of outstanding shares of Class A Common Stock is increased by a stock dividend payable in shares of Class A Common Stock, or by a split-up of shares of Class A Common Stock or other similar event, then, on the effective date of such stock dividend, split-up or similar event, the number of shares of Class A Common Stock issuable on exercise of each Public Warrant will be increased in proportion to such increase in the outstanding shares of Class A Common Stock. A rights offering to holders of Class A Common Stock entitling holders to purchase shares of Class A Common Stock at a price less than the fair market value will be deemed a stock dividend of a number of shares of Class A Common Stock equal to the product of (i) the number of shares of Class A Common Stock actually sold in such rights offering (or issuable under any other equity securities sold in such rights offering that are convertible into or exercisable for Class A Common Stock) multiplied by (ii) one (1) minus the quotient of (x) the price per share of Class A Common Stock paid in such rights offering divided by (y) the fair market value. For these purposes (i) if the rights offering is for securities convertible into or exercisable for Class A Common Stock, in determining the price payable for Class A Common Stock, there will be taken into account any consideration received for such rights, as well as any additional amount payable upon exercise or conversion and (ii) fair market value means the volume weighted average price of Class A Common Stock as reported during the 10 trading day period ending on the trading day prior to the first date on which the shares of Class A Common Stock trade on the applicable exchange or in the applicable market, regular way, without the right to receive such rights.

In addition, if the Company, at any time while the Public Warrants are outstanding and unexpired, pays a dividend or makes a distribution in cash, securities or other assets to the holders of Class A Common Stock on account of such shares of Class A Common Stock (or other shares of the Company's capital stock into which the Public Warrants are convertible), other than (a) as described above or (b) certain ordinary cash dividends, then the Public Warrant exercise price will be decreased, effective immediately after the effective date of such event, by the amount of cash and/or the fair market value of any securities or other assets paid on each share of Class A Common Stock in respect of such event.

If the number of outstanding shares of Class A Common Stock is decreased by a consolidation, combination, reverse stock split or reclassification of shares of Class A Common Stock or other similar event, then, on the effective date of such consolidation, combination, reverse stock split, reclassification or similar event, the number of shares of Class A Common Stock issuable on exercise of each Public Warrant will be decreased in proportion to such decrease in outstanding shares of Class A Common Stock.

Whenever the number of shares of Class A Common Stock purchasable upon the exercise of the Public Warrants is adjusted, as described above, the Public Warrant exercise price will be adjusted by

multiplying the exercise price immediately prior to such adjustment by a fraction (x) the numerator of which will be the number of shares of Class A Common Stock purchasable upon the exercise of the Public Warrants immediately prior to such adjustment, and (y) the denominator of which will be the number of shares of Class A Common Stock so purchasable immediately thereafter.

In case of any reclassification or reorganization of the outstanding shares of Class A Common Stock (other than those described above or that solely affects the par value of such shares of Class A Common Stock), or in the case of any merger or consolidation of the Company with or into another corporation (other than a consolidation or merger in which the Company is the continuing corporation and that does not result in any reclassification or reorganization of the Company's outstanding shares of Class A Common Stock), or in the case of any sale or conveyance to another corporation or entity of the assets or other property of the Company as an entirety or substantially as an entirety in connection with which the Company is dissolved, the holders of the Public Warrants will thereafter have the right to purchase and receive, upon the basis and upon the terms and conditions specified in the Public Warrants and in lieu of the shares of Class A Common Stock immediately theretofore purchasable and receivable upon the exercise of the rights represented thereby, the kind and amount of shares of stock or other securities or property (including cash) receivable upon such reclassification, reorganization, merger or consolidation, or upon a dissolution following any such sale or transfer, that the holder of the Public Warrants would have received if such holder had exercised their Public Warrants immediately prior to such event. If less than 70% of the consideration receivable by the holders of Class A Common Stock in such a transaction is payable in the form of Class A Common Stock in the successor entity that is listed for trading on a national securities exchange or is quoted in an established over-the-counter market, or is to be so listed for trading or quoted immediately following such event, and if the registered holder of the Public Warrant properly exercises the Public Warrant within 30 days following public disclosure of such transaction, the Public Warrant exercise price will be reduced as specified in the warrant agreement based on the Black-Scholes value (as defined in the warrant agreement) of the Public Warrant.

The Public Warrants may be exercised upon surrender of the warrant certificate on or prior to the expiration date at the offices of the warrant agent, with the exercise form on the reverse side of the warrant certificate completed and executed as indicated, accompanied by full payment of the exercise price (or on a cashless basis, if applicable), by certified or official bank check payable to the Company, for the number of Public Warrants being exercised. The Public Warrant holders do not have the rights or privileges of holders of Class A Common Stock and any voting rights until they exercise their Public Warrants and receive shares of Class A Common Stock. After the issuance of shares of Class A Common Stock upon exercise of the Public Warrants, each holder will be entitled to one vote for each share held of record on all matters to be voted on by stockholders.

No fractional shares will be issued upon exercise of the Public Warrants. If, upon exercise of the Public Warrants, a holder would be entitled to receive a fractional interest in a share, the Company will, upon exercise, round down to the nearest whole number of shares of Class A Common Stock to be issued to the Public Warrant holder.

The Public Warrants have been issued in registered form under a warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and the Company. The warrant agreement provides that the terms of the Public Warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by the holders of at least 50% of the then outstanding Public Warrants to make any change that adversely affects the interests of the registered holders of Public Warrants.

The Private Placement Warrants (including the Class A Common Stock issuable upon exercise of the Private Placement Warrants) will not be transferable, assignable or saleable until 30 days after the completion of the Business Combination (except, among other limited exceptions, to the Company's officers and directors and other persons or entities affiliated with our Sponsor) and they will not be redeemable by the Company so long as they are held by our Sponsor or its permitted transferees. Otherwise, the Private Placement Warrants have terms and provisions that are identical to those of the Public Warrants, including as to exercise price, exercisability and exercise period. If the Private Placement Warrants are held by holders other than our Sponsor or its permitted transferees, the Private Placement Warrants will be redeemable by the Company and exercisable by the holders on the same basis as the Public Warrants.

If holders of the Private Placement Warrants elect to exercise them on a cashless basis, they would pay the exercise price in the same manner as holders of Public Warrants as described above under "—Public Warrants." The reason that the Company has agreed that the Private Placement Warrants will be exercisable on a cashless basis so long as they are held by our Sponsor or its permitted transferees is because it was not known at the time of issuance whether our Sponsor would be affiliated with the Company following an initial business combination. If our Sponsor remains affiliated with the Company, its ability to sell the Company's securities in the open market will be significantly limited. The Company has policies in place that prohibit insiders from selling the Company's securities except during specific periods of time. Even during such periods of time when insiders will be permitted to sell the Company's securities, an insider cannot trade in the Company's securities if he or she is in possession of material non-public information. Accordingly, unlike public stockholders who could sell the shares of Class A Common Stock issuable upon exercise of the Public Warrants freely in the open market, the insiders could be significantly restricted from doing so. As a result, the Company believes that allowing the holders to exercise the Private Placement Warrants on a cashless basis is appropriate.

Our Sponsor has agreed not to transfer, assign or sell any of the Private Placement Warrants (including the Class A Common Stock issuable upon exercise of any of the Private Placement Warrants) until the date that is 30 days after the Closing Date, except to, among other limited exceptions, the Company's officers and directors and other persons or entities affiliated with our Sponsor.

The Private Placement Warrants were sold in a private placement pursuant to a purchase agreement between us and our Sponsor and have the terms set forth in a warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and the Company.

The transfer agent for our Class A Common Stock and Class C Common Stock and warrant agent for the Public Warrants and Private Placement Warrants is Continental Stock Transfer & Trust Company. We have agreed to indemnify Continental Stock Transfer & Trust Company in its roles as transfer agent and warrant agent, its agents and each of its stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence, willful misconduct or bad faith of the indemnified person or entity.

We are subject to the provisions of Section 203 of the DGCL regulating corporate takeovers. This statute prevents certain Delaware corporations, under certain circumstances, from engaging in a "business combination" with:

A "business combination" includes a merger or sale of more than 10% of our assets. However, the above provisions of Section 203 do not apply if:

Under our Charter, our board of directors is classified into three classes of directors. As a result, in most circumstances, a person can gain control of our board only by successfully engaging in a proxy contest at two or more annual meetings.

Our authorized but unissued common stock and preferred stock are available for future issuances without stockholder approval (including a specified future issuance) and could be utilized for a variety of corporate purposes, including future offerings to raise additional capital, acquisitions and employee benefit plans. The existence of authorized but unissued and unreserved common stock and preferred stock could render more difficult or discourage an attempt to obtain control of us by means of a proxy contest, tender offer, merger or otherwise.

Our Bylaws provide that special meetings of our stockholders may be called only by a majority vote of our board of directors, by our Chief Executive Officer or by our Chairman.

Our Bylaws provide that stockholders seeking to bring business before our annual meeting of stockholders, or to nominate candidates for election as directors at our annual meeting of stockholders, must provide timely notice of their intent in writing. To be timely, a stockholder's notice will need to be received by the company secretary at our principal executive offices not later than the close of business on the 90th day nor earlier than the close of business on the 120th day prior to the anniversary date of the immediately preceding annual meeting of stockholders. Pursuant to Rule 14a-8 of the Exchange Act, proposals seeking inclusion in our annual proxy statement must comply with the notice periods contained therein. Our Bylaws also specify certain requirements as to the form and content of a stockholders' meeting. These provisions may preclude our stockholders from bringing matters before

our annual meeting of stockholders or from making nominations for directors at our annual meeting of stockholders.

Pursuant to Rule 144, a person who has beneficially owned restricted shares of our Class A Common Stock or warrants for at least six months would be entitled to sell their securities provided that (i) such person is not deemed to have been one of our affiliates at the time of, or at any time during the three months preceding, a sale and (ii) we are subject to the Exchange Act periodic reporting requirements for at least three months before the sale and have filed all required reports under Section 13 or 15(d) of the Exchange Act during the 12 months (or such shorter period as we were required to file reports) preceding the sale.

Persons who have beneficially owned restricted shares of our Class A Common Stock or warrants for at least six months but who are our affiliates at the time of, or at any time during the three months preceding, a sale, would be subject to additional restrictions, by which such person would be entitled to sell within any three-month period only a number of securities that does not exceed the greater of:

Sales by our affiliates under Rule 144 are also limited by manner of sale provisions and notice requirements and to the availability of current public information about us.

Rule 144 is not available for the resale of securities initially issued by shell companies (other than business combination related shell companies) or issuers that have been at any time previously a shell company. However, Rule 144 also includes an important exception to this prohibition if the following conditions are met:

As a result, if we have filed all Exchange Act reports and materials as set forth in the third bullet of the preceding paragraph, then our initial stockholders will be able to sell their founder shares and Private Placement Warrants, as applicable, pursuant to Rule 144 without registration one year following the completion of the Business Combination.

The Company's Class A Common Stock and Public Warrants are currently quoted on NASDAQ under the symbols "CDEV" and "CDEVW," respectively. Through October 11, 2016, our Class A Common Stock, Public Warrants and Units were quoted under the symbols "SRAQ," "SRAQW," and "SRAQU," respectively. Upon the consummation of the Business Combination, we separated our Units into their component securities of one share of Class A Common Stock and one-third of one Public Warrant, and the Units ceased public trading.

The following discussion is a summary of the material U.S. federal income tax consequences to Non-U.S. Holders (as defined below) of the purchase, ownership and disposition of our Class A Common Stock issued pursuant to this offering, but does not purport to be a complete analysis of all potential tax effects. The effects of other U.S. federal tax laws, such as estate and gift tax laws, and any applicable state, local or non-U.S. tax laws are not discussed. This discussion is based on the Code, Treasury regulations promulgated thereunder ("Treasury Regulations"), judicial decisions, and published rulings and administrative pronouncements of the U.S. Internal Revenue Service (the "IRS"), in each case as in effect as of the date hereof. These authorities may change or be subject to differing interpretations. Any such change or differing interpretation may be applied retroactively in a manner that could adversely affect a Non-U.S. Holder of our Class A Common Stock. We have not sought and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance the IRS or a court will not take a contrary position to that discussed below regarding the tax consequences of the purchase, ownership and disposition of our Class A Common Stock.

This discussion is limited to Non-U.S. Holders that hold our Class A Common Stock as a "capital asset" within the meaning of Section 1221 of the Code (generally, property held for investment). This discussion does not address all U.S. federal income tax consequences relevant to a Non-U.S. Holder's particular circumstances, including the impact of the Medicare contribution tax on net investment income. In addition, it does not address consequences relevant to Non-U.S. Holders subject to special rules, including, without limitation:

If an entity treated as a partnership for U.S. federal income tax purposes holds our Class A Common Stock, the tax treatment of a partner in the partnership will depend on the status of the partner, the activities of the partnership and certain determinations made at the partner level. Accordingly, partnerships holding our Class A Common Stock and partners in such partnerships should consult their tax advisors regarding the U.S. federal income tax consequences to them.

THIS DISCUSSION IS FOR INFORMATIONAL PURPOSES ONLY AND IS NOT TAX ADVICE. INVESTORS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR CLASS A COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL OR NON-U.S. TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

For purposes of this discussion, a "Non-U.S. Holder" is any beneficial owner of our Class A Common Stock that is neither a "U.S. person" nor an entity treated as a partnership for U.S. federal income tax purposes. A U.S. person is any person that, for U.S. federal income tax purposes, is or is treated as any of the following:

As described in the section entitled "Dividend Policy" we do not anticipate declaring or paying dividends to holders of our Class A Common Stock in the foreseeable future. However, if we do make distributions of cash or property on our Class A Common Stock, such distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Amounts not treated as dividends for U.S. federal income tax purposes will constitute a return of capital and first be applied against and reduce a Non-U.S. Holder's adjusted tax basis in its Class A Common Stock, but not below zero. Any excess will be treated as capital gain and will be treated as described below under "—Sale or Other Taxable Disposition."

Subject to the discussion below on effectively connected income, dividends paid to a Non-U.S. Holder of our Class A Common Stock will be subject to U.S. federal withholding tax at a rate of 30% of the gross amount of the dividends (or such lower rate specified by an applicable income tax treaty, provided the Non-U.S. Holder furnishes a valid IRS Form W-8BEN or W-8BEN-E (or other applicable documentation) certifying qualification for the lower treaty rate). A Non-U.S. Holder that does not timely furnish the required documentation, but that qualifies for a reduced treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. Non-U.S. Holders should consult their tax advisors regarding their entitlement to benefits under any applicable income tax treaty.

If dividends paid to a Non-U.S. Holder are effectively connected with the Non-U.S. Holder's conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such dividends are attributable), the Non-U.S. Holder will be exempt from the U.S. federal withholding tax described above. To claim the exemption, the Non-U.S. Holder must furnish to the applicable

withholding agent a valid IRS Form W-8ECI, certifying that the dividends are effectively connected with the Non-U.S. Holder's conduct of a trade or business within the United States.

Any such effectively connected dividends will be subject to U.S. federal income tax on a net income basis at the regular graduated rates. A Non-U.S. Holder that is a corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include such effectively connected dividends. Non-U.S. Holders should consult their tax advisors regarding any applicable tax treaties that may provide for different rules.

A Non-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other taxable disposition of our Class A Common Stock unless:

Gain described in the first bullet point above generally will be subject to U.S. federal income tax on a net income basis at the regular graduated rates. A Non-U.S. Holder that is a corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on its effectively connected earnings and profits (adjusted for certain items), which will include such effectively connected gain.

A Non-U.S. Holder described in the second bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on any gain derived from the disposition, which may be offset by U.S. source capital losses of the Non-U.S. Holder (even though the individual is not considered a resident of the United States), provided the Non-U.S. Holder has timely filed U.S. federal income tax returns with respect to such losses.

With respect to the third bullet point above, we believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, a Non-U.S. Holder of our Class A Common Stock generally will not be subject to U.S. net federal income tax as a result of our being a USRPHC if our Class A Common Stock is "regularly traded," as defined by applicable Treasury Regulations, on an established securities market, and such Non-U.S. Holder owned, actually or constructively, 5% or less of our Class A Common Stock throughout the shorter of the five-year period ending on the date of the sale or other taxable disposition or the Non-U.S. Holder's holding period. If our Class A Common Stock is not considered to be so traded, a Non-U.S. Holder generally would be subject to net U.S. federal income tax on the gain realized on a disposition of our Class A Common Stock as a result of our being a USRPHC and generally would be required to file a U.S. federal income tax return. Additionally, a 15% withholding tax would apply to the gross proceeds from such disposition.

Non-U.S. Holders should also consult their tax advisors regarding potentially applicable income tax treaties that may provide for different rules.

Payments of dividends on our Class A Common Stock will not be subject to backup withholding, provided the applicable withholding agent does not have actual knowledge or reason to know the Non-U.S. Holder is a United States person and the Non-U.S. Holder either certifies its non-U.S. status, such as by furnishing a valid IRS Form W-8BEN, W-8BEN-E or W-8ECI, or otherwise establishes an exemption. However, information returns are required to be filed with the IRS in connection with any dividends on our Class A Common Stock paid to the Non-U.S. Holder, regardless of whether any tax was actually withheld. In addition, proceeds of the sale or other taxable disposition of our Class A Common Stock within the United States or conducted through certain U.S.-related brokers generally will not be subject to backup withholding or information reporting if the applicable withholding agent receives the certification described above and does not have actual knowledge or reason to know that such Non-U.S. Holder is a United States person, or the Non-U.S. Holder otherwise establishes an exemption. Proceeds of a disposition of our Class A Common Stock conducted through a non-U.S. office of a non-U.S. broker generally will not be subject to backup withholding or information reporting.

Copies of information returns that are filed with the IRS may also be made available under the provisions of an applicable treaty or agreement to the tax authorities of the country in which the Non-U.S. Holder resides or is established.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a Non-U.S. Holder's U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

Withholding taxes may be imposed under Sections 1471 to 1474 of the Code (such Sections commonly referred to as the Foreign Account Tax Compliance Act, or "FATCA") on certain types of payments made to non-U.S. financial institutions and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on dividends on, or gross proceeds from the sale or other disposition of, our Class A Common Stock paid to a "foreign financial institution" or a "non-financial foreign entity" (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (1) the foreign financial institution undertakes certain diligence and reporting obligations, (2) the non-financial foreign entity either certifies it does not have any "substantial United States owners" (as defined in the Code) or furnishes identifying information regarding each direct and indirect substantial United States owner, or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as IRS Form W-8BEN-E). If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in (1) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain "specified United States persons" or "United States-owned foreign entities" (each as defined in the Code), annually report certain information about such accounts, and withhold 30% on certain payments to non-compliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.

Under the applicable Treasury Regulations and administrative guidance, withholding under FATCA generally applies to payments of dividends on our Class A Common Stock, and will apply to payments of gross proceeds from the sale or other disposition of such stock on or after January 1, 2019.

Prospective investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in our Class A Common Stock.

The validity of the securities offered hereby will be passed upon for us by Latham & Watkins LLP of Houston, Texas. Any underwriters or agents will be advised about other issues relating to the offering by counsel to be named in the applicable prospectus supplement.

The consolidated and combined financial statements of Centennial Resource Production, LLC and Celero Energy Company, LP (Predecessor) as of December 31, 2015 and 2014, and each of the years in the three-year period ended December 31, 2015, have been included herein and in the registration statement in reliance upon the reports of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

Estimates of our oil and natural gas reserves and related future net cash flows related to our properties as of December 31, 2015 and December 31, 2014 included herein and elsewhere in the registration statement were based upon a reserve report prepared by our independent petroleum engineer, Netherland, Sewell & Associates, Inc. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the shares of Class A Common Stock offered by this prospectus. This prospectus does not contain all of the information included in the registration statement. For further information pertaining to us and our Class A Common Stock you should refer to the registration statement and its exhibits. Statements contained in this prospectus concerning any of our contracts, agreements or other documents are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed. Each statement in this prospectus relating to a contract or document filed as an exhibit is qualified in all respects by the filed exhibit.

We are subject to the informational requirements of the Exchange Act and file annual, quarterly and current reports and other information with the SEC. Our filings with the SEC are available to the public on the SEC's website at http://www.sec.gov. Those filings are also available to the public on, or accessible through, our website under the heading "Investors" at www.cdevinc.com. The information we file with the SEC or contained on or accessible through our corporate website or any other website that we may maintain is not part of this prospectus or the registration statement of which this prospectus is a part. You may also read and copy, at SEC prescribed rates, any document we file with the SEC, including the registration statement (and its exhibits) of which this prospectus is a part, at the SEC's Public Reference Room located at 100 F Street, N.E., Washington D.C. 20549. You can call the SEC at 1-800-SEC-0330 to obtain information on the operation of the Public Reference Room.

	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.

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.

CENTENNIAL RESOURCE PRODUCTION, LLC
(Predecessor)

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN OWNER'S EQUITY

(Unaudited)

(In Thousands)

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

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.

CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

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.

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.

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

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.

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.

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.

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.

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

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

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.

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:

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.

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:

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:

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.

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):

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.

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

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

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.

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.

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.

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:

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

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.

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.

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.

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

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

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

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.

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

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

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 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.

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.

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.

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.

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

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 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.

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.

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.

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

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 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.

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.

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

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.

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.

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:

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.

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

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.

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.

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.

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.

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.

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.

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.

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):

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

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:

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:

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.

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

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.

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.

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.

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:

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:

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

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.

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.

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.

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:

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.

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

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:

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.

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

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:

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.

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

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:

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.

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.

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.

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.

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

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.

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

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

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.

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"):

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

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.

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:

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

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 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:

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

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.

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)

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)

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

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.

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.

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

(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.

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

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

(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.

The following are abbreviations and definitions of certain terms used in this prospectus, 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.

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.

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

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.

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.

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.

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 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

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.

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.

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.

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.

The following table sets forth the costs and expenses payable by the registrant in connection with this offering. All of the amounts shown are estimates except the Securities and Exchange Commission (the "SEC") registration fee.

We will bear all costs, expenses and fees in connection with the registration of the shares of Class A Common Stock, including with regard to compliance with state securities or "blue sky" laws. The selling stockholders, however, will bear all commissions and discounts, if any, attributable to their sale of shares of Class A Common Stock.

Reference is made to Section 102(b)(7) of the Delaware General Corporation Law (the "DGCL"), which enables a corporation in its original certificate of incorporation or an amendment thereto to eliminate or limit the personal liability of a director for violations of the director's fiduciary duty, except (1) for any breach of the director's duty of loyalty to the corporation or its stockholders; (2) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law; (3) pursuant to Section 174 of the DGCL, which provides for liability of directors for unlawful payments of dividends or unlawful stock purchases or redemptions or; (4) for any transaction from which a director derived an improper personal benefit.

Reference is also made to Section 145 of the DGCL, which provides that a corporation may indemnify any person, including an officer or director, who was or is, or is threatened to be made, party to any threatened, pending or completed legal action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of such corporation) by reason of the fact that such person is or was an officer, director, employee or agent of such corporation or is or was serving at the request of such corporation as a director, officer, employee or agent of another corporation or enterprise. The indemnity may include expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding, provided such officer, director, employee or agent acted in good faith and in a manner he reasonably believed to be in, or not opposed to, the corporation's best interest and, for criminal proceedings, had no reasonable cause to believe that his conduct was unlawful. A Delaware corporation may indemnify any officer or director in an action by or in the right of the corporation under the same conditions, except that no indemnification is permitted without judicial approval if the officer or director is adjudged to be liable to the corporation. Where an officer or director is successful on the merits or otherwise in the defense of any action referred to above, the corporation must indemnify him against the expenses that such officer or director actually and reasonably incurred in connection therewith.

In accordance with Section 102(b)(7) of the DGCL, our second amended and restated certificate of incorporation (our "Charter") provides that no director shall be personally liable to us or any of our stockholders for monetary damages resulting from breaches of its fiduciary duty as a director, except to the extent such limitation on or exemption from liability is not permitted under the DGCL unless he or she violated their duty of loyalty to the Registrant or its stockholders, acted in bad faith, knowingly or

intentionally violated the law, authorized unlawful payments of dividends, unlawful stock purchases or unlawful redemptions, or derived improper personal benefit from their actions as directors. The effect of this provision of Charter is to eliminate our rights and those of our stockholders (through stockholders' derivative suits on our behalf) to recover monetary damages against a director for breach of the fiduciary duty of care as a director, including breaches resulting from negligent or grossly negligent behavior, except, as restricted by Section 102(b)(7) of the DGCL. However, this provision does not limit or eliminate our rights or the rights of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director's duty of care.

If the DGCL is amended to authorize corporate action further eliminating or limiting the liability of directors, then, in accordance with our Charter, the liability of our directors to us or our stockholders will be eliminated or limited to the fullest extent authorized by the DGCL, as so amended. Any repeal or amendment of provisions of our Charter limiting or eliminating the liability of directors, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to further limit or eliminate the liability of directors on a retroactive basis.

Our Charter also provides that we will, to the fullest extent authorized or permitted by applicable law, indemnify our current and former officers and directors, as well as those persons who, while directors or officers of our corporation, are or were serving as directors, officers, employees or agents of another entity, trust or other enterprise, including service with respect to an employee benefit plan, in connection with any threatened, pending or completed proceeding, whether civil, criminal, administrative or investigative, against all expense, liability and loss (including, without limitation, attorney's fees, judgments, fines, ERISA excise taxes and penalties and amounts paid in settlement) reasonably incurred or suffered by any such person in connection with any such proceeding. Notwithstanding the foregoing, a person eligible for indemnification pursuant to our Charter will be indemnified by us in connection with a proceeding initiated by such person only if such proceeding was authorized by our board of directors, except for proceedings to enforce rights to indemnification.

The right to indemnification conferred by our Charter is a contract right that includes the right to be paid by us the expenses incurred in defending or otherwise participating in any proceeding referenced above in advance of its final disposition, provided, however, that if the DGCL requires, an advancement of expenses incurred by our officer or director (solely in the capacity as an officer or director of our corporation) will be made only upon delivery to us of an undertaking, by or on behalf of such officer or director, to repay all amounts so advanced if it is ultimately determined that such person is not entitled to be indemnified for such expenses under our Charter or otherwise.

The rights to indemnification and advancement of expenses will not be deemed exclusive of any other rights which any person covered by our Charter may have or hereafter acquire under law, our Charter, our amended and restated bylaws (our "Bylaws"), an agreement, vote of stockholders or disinterested directors, or otherwise.

Any repeal or amendment of provisions of our Charter affecting indemnification rights, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing at the time of such repeal or amendment or adoption of such inconsistent provision with respect to any act or omission occurring prior to such repeal or amendment or adoption of such inconsistent provision. Our Charter will also permit us, to the extent and in the manner authorized or permitted by law, to indemnify and to advance expenses to persons other that those specifically covered by our Charter.

Our Bylaws include the provisions relating to advancement of expenses and indemnification rights consistent with those set forth in our Charter. In addition, our Bylaws provide for a right of indemnity to bring a suit in the event a claim for indemnification or advancement of expenses is not paid in full by us within a specified period of time. Our Bylaws also permit us to purchase and maintain insurance, at our expense, to protect us and/or any director, officer, employee or agent of our corporation or another entity, trust or other enterprise against any expense, liability or loss, whether or not we would have the power to indemnify such person against such expense, liability or loss under the DGCL.

Any repeal or amendment of provisions of our Bylaws affecting indemnification rights, whether by our board of directors, stockholders or by changes in applicable law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing thereunder with respect to any act or omission occurring prior to such repeal or amendment or adoption of such inconsistent provision.

We have entered into indemnity agreements with each of our officers and directors. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law and to advance expenses incurred as a result of any proceeding against them to which they could be indemnified.

Since our formation, we have sold the following securities without registration under the Securities Act:

On November 6, 2015, our Sponsor purchased the founder shares for $25,000, or approximately $0.002 per share. On February 5, 2016, our Sponsor transferred 40,000 founder shares to each of the Company's then independent directors at their original purchase price. Immediately prior to the pricing of our IPO, the Company effected a stock dividend with respect to its Class B Common Stock of 1,437,500 shares, resulting in the initial stockholders holding an aggregate of 12,937,500 founder shares. On April 8, 2016, following the expiration of the underwriters' remaining over-allotment option, our Sponsor forfeited 437,500 founder shares, so that the remaining founder shares held by the initial stockholders would represent 20% of the outstanding shares of common stock. The founder shares were issued in connection with our organization pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.

Simultaneously with the consummation of our IPO, our Sponsor purchased from the Company an aggregate of 8,000,000 Private Placement Warrants at a price of $1.50 per Private Placement Warrant (for a purchase price of $12,000,000). Each Private Placement Warrant entitles the holder thereof to purchase one share of Class A Common Stock at an exercise price of $11.50 per share. The sale of the Private Placement Warrants was made pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.

On the Closing Date, we completed the Private Placements for approximately $1.01 billion in aggregate proceeds, which were used to fund a portion of the cash consideration in the Business Combination. The shares of Class A Common Stock sold in the Private Placements were issued pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.

On the Closing Date, the Company issued 20,00,000 shares of Class C Common Stock to the Centennial Contributors and one share of Series A Preferred Stock to CRD in connection with the Business Combination. These issuances were made pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.

On the Closing Date, following the Closing, the Company issued 844,079 shares of Class A Common Stock to an accredited investor at the direction of members of CRP affiliated with such investor (the "CRP Members"), in exchange for 844,079 CRP Common Units held by such CRP Members. Upon the exchange of the CRP Common Units, the Company canceled 844,079 shares of Class C Common Stock held by the CRP Members. The issuance of the shares of Class A Common Stock was made pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.

See the Exhibit Index, which follows the signature page and which is incorporated by reference herein.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-1 and has duly caused this Registration Statement on Form S-1 to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, Colorado on November 16, 2016.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

		Description of Exhibits

2.1		Contribution Agreement, dated as of July 6, 2016, as amended by Amendment No. 1 thereto, dated as of July 29, 2016, among Centennial Resource Development, LLC, NGP Centennial Follow-On LLC, Celero Energy Company, LP, Centennial Resource Production, LLC and New Centennial, LLC (incorporated by reference to Annex A of the Registrant's definitive proxy statement filed with the SEC on September 23, 2016).

3.1		Second Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed with the SEC on October 11, 2016).

3.2		Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed with the SEC on October 7, 2016).

3.3	+	Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC dated as of October 11, 2016.

4.1		Specimen Class A Common Stock Certificate (incorporated by reference to Exhibit 4.2 to the Registrant's Registration Statement on Form S-1 (Registration No. 333-209140) filed with the SEC on January 27, 2016).

4.2		Specimen Warrant Certificate (incorporated by reference to Exhibit 4.3 to the Registrant's Registration Statement on Form S-1 (Registration No. 333-209140) filed with the SEC on January 27, 2016).

4.3		Warrant Agreement between Continental Stock Transfer & Trust Company and the Registrant (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed with the SEC on February 29, 2016).

4.4		Certificate of Designation of Series A Preferred Stock (incorporated by reference to Exhibit 3.2 to the Registrant's Current Report on Form 8-K filed with the SEC on October 11, 2016).

5.1	+	Opinion of Latham & Watkins LLP.

10.1		Amended and Restated Registration Rights Agreement among the Registrant and certain stockholders (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed with the SEC on October 11, 2016).

10.2		Sponsor Warrants Purchase Agreement, dated February 23, 2016, between the Registrant and Silver Run Sponsor, LLC (incorporated by reference to Exhibit 10.5 to the Registrant's Current Report on Form 8-K filed with the SEC on February 29, 2016).

10.3		Form of Indemnity Agreement (incorporated by reference to Exhibit 10.7 to the Registrant's Registration Statement on Form S-1 (Registration No. 333-209140) filed with the SEC on January 27, 2016).

10.4		Amended and Restated Credit Agreement, dated as of October 15, 2014, among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-1 of Centennial Resource Development, Inc. (Registration No. 333-212185) filed with the SEC on June 22, 2016).

		Description of Exhibits

10.5		First Amendment to Amended and Restated Credit Agreement, dated as of May 6, 2015, among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and guarantors party thereto (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-1 of Centennial Resource Development, Inc. (Registration No. 333-212185) filed with the SEC on June 22, 2016).

10.6		Second Amendment to Amended and Restated Credit Agreement, dated as of October 11, 2016, by and among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and guarantors party thereto (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed with the SEC on October 11, 2016).

10.7		Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Registrant's Current Report on Form 8-K filed with the Commission on October 11, 2016).

10.8		Form of Stock Option Agreement under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Registrant's Current Report on Form 8-K filed with the Commission on October 11, 2016).

10.9		Form of Restricted Stock Unit Agreement under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed with the Commission on October 11, 2016).

10.10		Form of Restricted Stock Agreement under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (incorporated by reference to Exhibit 10.9 to the Registrant's Current Report on Form 8-K filed with the Commission on October 11, 2016).

21.1	+	Subsidiaries of the Registrant.

23.1	*	Consent of KPMG LLP.

23.2	*	Consent of Netherland, Sewell & Associates, Inc.

23.3	+	Consent of Latham & Watkins LLP (included in Exhibit 5.1).

24.1	+	Power of Attorney (included on signature pages of this Registration Statement).

99.1	+	Netherland, Sewell & Associates, Inc., Summary of Reserves at December 31, 2014.

99.2	+	Netherland, Sewell & Associates, Inc., Summary of Reserves at December 31, 2015.

#101.INS	*	XBRL Instance Document.

#101.SCH	*	XBRL Taxonomy Extension Schema Document.

#101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase Document.

#101.DEF	*	XBRL Taxonomy Extension Definition Linkbase Document.

#101.LAB	*	XBRL Taxonomy Extension Label Linkbase Document.


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

	Class A Common Stock (CDEV)

	High		Low
Fiscal 2016:
Fourth Quarter(1)	$	16.96	$	14.09
Third Quarter	$	16.10	$	9.65
Second Quarter(2)	$	10.70	$	9.80
First Quarter(3)		N/A		N/A

	Permian Basin(1)

	Delaware Wolfcamp, Bone Spring		Midland Wolfcamp, Spraberry		Eagle Ford		Bakken / Three Forks
Fourth Quarter 2012		22.5		49.6		112.5		78.2
Fourth Quarter 2013		33.8		61.4		164.0		101.0
Fourth Quarter 2014		56.9		86.1		219.2		130.3
Fourth Quarter 2015		72.6		91.8		205.9		127.1

Estimated Total Proved Reserves

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

Developed Acreage				Undeveloped Acreage				Total Acreage

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


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


PROSPECTUS SUMMARY			1
RISK FACTORS			8
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			35
USE OF PROCEEDS			37
DETERMINATION OF OFFERING PRICE			37
PRICE RANGE OF SECURITIES AND DIVIDENDS			37
SELECTED HISTORICAL FINANCIAL INFORMATION			39
DESCRIPTION OF BUSINESS			43
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			72
MANAGEMENT			100
EXECUTIVE COMPENSATION			107
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			119
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			124
SELLING STOCKHOLDERS			129
PLAN OF DISTRIBUTION			132
DESCRIPTION OF CAPITAL STOCK			135
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS			143
LEGAL MATTERS			148
EXPERTS			148
WHERE YOU CAN FIND MORE INFORMATION			148
INDEX TO FINANCIAL STATEMENTS			F-1
ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS			A-1

		Total

Zones:
3rd Bone Spring Sandstone			64
Upper Wolfcamp A			403
Lower Wolfcamp A			335
Wolfcamp B			311
Wolfcamp C			275

Total Horizontal Locations(3)(4)			1,388



County:
Reeves	76,600	36,400
Ward	2,400	1,900
Pecos	11,800	4,000

Total	90,800	42,300

	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

Description & Production Period		Weighted Average Swap Price ($/MMbtu)(1)

Natural Gas Swaps:
January 2017 - December 2017	1,460,000	$	2.94

Name		Position

Mark G. Papa	70	President, Chief Executive Officer and Chairman of the Board	III
George S. Glyphis	46	Chief Financial Officer	—
Sean R. Smith	43	Chief Operating Officer	—
Maire A. Baldwin	50	Director	I
Robert M. Tichio	39	Director	I
Karl E. Bandtel	50	Director	II
Jeffrey H. Tepper	50	Director	II
David M. Leuschen	65	Director	III
Pierre F. Lapeyre, Jr.	54	Director	III
Tony R. Weber	54	Director	—	(2)

Name and Principal Position

Ward Polzin, Chief Executive Officer	2015	250,000	62,500	0	14,417	326,917
George S. Glyphis, Vice President and Chief Financial Officer	2015	275,000	68,750	0	25,077	368,827
Bret Siepman, Vice President, Development	2015	250,000	62,500	0	14,417	326,917

Named Executive Officer

Mark G. Papa	800,000	—
George S. Glyphis	350,000	100
Sean R. Smith	385,000	100

		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

	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

	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

	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

	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

	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

	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

	Level 1		Level 2		Level 3

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

	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

	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

	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	)

	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

	Level 1		Level 2		Level 3

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



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		—		—		—



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		—		—		—



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	—		—		—		—		—

Years Ending December 31,	Amount

	(in thousands)
2016	$	2,676
2017		477
2018		485
2019		419
2020		—
Thereafter		—

Total	$	4,057

	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

	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


SEC Registration Fee	$	224,657
Legal Fees and Expenses		75,000
Accounting Fees and Expenses		30,000
Other		10,000

Total	$	339,657


		CENTENNIAL RESOURCE DEVELOPMENT, INC.
		By:		/s/ GEORGE S. GLYPHIS George S. Glyphis Chief Financial Officer, Treasurer and Assistant Secretary