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

FORM 10-K
þ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2016
or
o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission file number 001-37697

 
CENTENNIAL RESOURCE DEVELOPMENT, INC.
(Exact name of registrant as specified in its charter)
 
Delaware
 
47-5381253
(State of Incorporation)
 
(I.R.S. Employer Identification No.)
 
 
 
1401 Seventeenth Street, Suite 1000, Denver, Colorado 80202
(Address of principal executive offices including zip code)
(Registrant’s telephone number, including area code): (720) 441-5515
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Class A Common Stock, par value $0.0001 per share
 
The NASDAQ Capital Market LLC
Warrants, each exercisable for one share of Class A Common Stock
 
The NASDAQ Capital Market LLC
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  o No  ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  o No  ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days.    Yes  ý No  o
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý No  o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ý
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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act).
Large accelerated filer  o
 
Accelerated filer  o
 
Non-accelerated filer  ý
(Do not check if a smaller reporting company)
 
Smaller reporting company  o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o No  ý
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant as of June 30, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $488,726,000 based on the closing price of the shares of common stock on that date.
As of March 7, 2017 , there were 201,882,082 shares of Class A Common Stock, par value $0.0001 per share, no shares of Class B Common Stock, par value $0.0001 per share, and 19,155,921 shares of Class C Common Stock, par value $0.0001 per share, outstanding.

 



TABLE OF CONTENTS
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 





Table of Contents

GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this Annual Report on Form 10-K, which are commonly used in the oil and natural gas industry:
Bbl . One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.
Bbl/d . One Bbl per day.
Bcf . One billion cubic feet of natural gas.
Boe . One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
Boe/d . One Boe per day.
Btu . One British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree 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.
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.
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.
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.
Formation . A layer of rock which has distinct characteristics that differs from nearby rock.
Horizontal drilling . A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
MBbl . One thousand barrels of crude oil, condensate or NGLs.
MBoe . One thousand Boe.
Mcf . One thousand cubic feet of natural gas.
Mcf/d . One Mcf per day.
MMBbl . One million barrels of crude oil, condensate or NGLs.
MMBoe . One million Boe.
MMBtu . One million British thermal units.
MMcf . One million cubic feet of natural gas.
NGLs . Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.
NYMEX . The New York Mercantile Exchange.
Operator . The individual or company responsible for the development and/or production of an oil or natural gas well or lease.

3

Table of Contents

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 . The estimated quantities of oil, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Realized price . The cash market price less all expected quality, transportation and demand adjustments.
Recompletion . The completion for production of an existing wellbore in another formation from that which the well has been previously completed
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.
Spot market price . The cash market price without reduction for expected quality, transportation and demand adjustments.
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.
WTI . West Texas Intermediate.






4

Table of Contents

GLOSSARY OF CERTAIN OTHER TERMS
The following are definitions of certain other terms that are used in this Annual Report on Form 10-K:
Business Combination. The acquisition of approximately 89% of the outstanding membership interests in CRP from the Centennial Contributors, which closed on October 11, 2016, and the other transactions contemplated by the Contribution Agreement.
Business Combination Private Placements. The issuance and sale in private placements of (i) 81,005,000 shares of Class A Common Stock to Riverstone Centennial Holdings, L.P. and (ii) 20,000,000 shares of Class A Common Stock to certain other investors, which closed simultaneously with the consummation of the Business Combination.
Celero. Celero Energy Company, LP, a Delaware limited partnership.
Centennial Contributors. CRD, NGP Follow-On and Celero, collectively.
The Company, We, Our or Us. (a) Centennial Resource Development, Inc. and its subsidiaries, including CRP, following the closing of the Business Combination and (b) Silver Run Acquisition Corporation prior to the closing of the Business Combination.
Class A Common Stock. Our Class A Common Stock, par value $0.0001 per share.
Class B Common Stock. Our Class B Common Stock, par value $0.0001 per share.
Class C Common Stock. Our Class C Common Stock, par value $0.0001 per share, which were issued to the Centennial Contributors in connection with the Business Combination.
Contribution Agreement . The Contribution Agreement, dated as of July 6, 2016, among the Centennial Contributors, CRP and NewCo, as amended by Amendment No. 1 thereto, dated as of July 29, 2016, and the Joinder Agreement, dated as of October 7, 2016, by the Company.
CRD . Centennial Resource Development, LLC, a Delaware limited liability company.
CRP . Centennial Resource Production, LLC, a Delaware limited liability company.
CRP Common Units . The units representing common membership interests in CRP.
Founder Shares. Shares of our Class B Common Stock purchased by our Sponsor in a private placement prior to our IPO, which were converted into shares of Class A Common Stock on a one-for-one basis in connection with the closing of the Business Combination.
Initial Stockholders . Holders of our founder shares prior to our IPO, including our Sponsor and our independent directors prior to the Business Combination.
IPO . Our initial public offering of units, which closed on February 29, 2016.
NewCo . New Centennial, LLC, a Delaware limited liability company controlled by affiliates of Riverstone.
NGP Follow-On . NGP Centennial Follow-On LLC, a Delaware limited liability company.
Private Placement Warrants . Our 8,000,000 outstanding warrants, which were purchased by our Sponsor in a private placement simultaneously with the closing of our IPO.
Public Warrants . Our 16,666,643 outstanding warrants, which were sold as part of the Units in our IPO.
Riverstone . Riverstone Investment Group LLC and its affiliates, including our Sponsor, collectively.
Riverstone Purchasers . Riverstone VI Centennial QB Holdings, L.P., Riverstone Non-ECI USRPI AIV, L.P. and REL US Centennial Holdings, LLC, which are affiliates of Riverstone.
Series B Preferred Stock . Our Series B Preferred Stock, par value $0.0001 per share.
Series B Preferred Units . Series B Preferred Units of CRP which, by their terms, convert to CRP Common Units upon the conversion of the Series B Preferred Stock.
Silverback Acquisition . Our acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and Silverback Operating, LLC, which closed on December 28, 2016.
Silverback Acquisition Private Placements . The issuance and sale in private placements of (i) 3,473,590 shares of Class A Common Stock and 104,400 shares of Series B Preferred Stock to the Riverstone Purchasers and (ii) 33,012,380 shares of our

5

Table of Contents

Class A Common Stock to certain other investors, which closed simultaneously with the consummation of the Silverback Acquisition.
Sponsor . Our sponsor, Silver Run Sponsor, LLC, a Delaware limited liability company and an affiliate of Riverstone.
Units . Our units sold in our IPO, each of which consisted of one share of Class A Common Stock and one-third of one Public Warrant.
V oting common stock . Our Class A Common Stock and Class C Common Stock.

6

Table of Contents

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Throughout this Form 10-K, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, 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 Form 10-K, 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 Part I, Item 1A. Risk Factors in this annual report.
Forward-looking statements may include statements about:
our business strategy; 
our reserves; 
our drilling prospects, inventories, projects and programs; 
our ability to replace the reserves we produce through drilling and property acquisitions; 
our financial strategy, liquidity and capital required for our development program; 
our realized oil, natural gas and natural gas liquids ("NGL") prices; 
the timing and amount of our future production of oil, natural gas and NGLs; 
our hedging strategy and results; 
our future drilling plans; 
our competition and government regulations; 
our ability to obtain permits and governmental approvals; 
our pending legal or environmental matters; 
our marketing of oil, natural gas and NGLs; 
our leasehold or business acquisitions; 
our costs of developing our properties; 
general economic conditions; 
credit markets; 
uncertainty regarding our future operating results; and 
our plans, objectives, expectations and intentions contained in this prospectus that are not historical.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the 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 Part I, Item 1A. 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 Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

7

Table of Contents

All forward-looking statements, expressed or implied, included in this Form 10-K 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 Form 10-K.


8

Table of Contents

PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
Corporate History
Centennial Resource Development, Inc. (the “Company,” “Centennial,” “we,” “us,” or “our”) was originally incorporated in Delaware on November 4, 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.
On February 29, 2016, we consummated our initial public offering of Units each consisting of one share of Class A Common Stock and one-third of one Public Warrant. On October 11, 2016, we consummated the acquisition of approximately 89% of the outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company (“CRP” and such acquisition, the “Business Combination”).
CRP was formed in August 2012 by an affiliate of NGP Energy Capital Management, a family of energy-focused private equity investment funds, in connection with the acquisition of all of the oil and natural gas properties and certain other assets of Celero, which was formed in 2006 to focus on the development and acquisition of oil and natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas. Until the closing of the Business Combination, CRP operated as a privately-held independent oil and natural gas company.
Our Class A Common Stock and Public Warrants trade on The NASDAQ Capital Market (“NASDAQ”) under the ticker symbols “CDEV” and “CDEVW,” respectively. The Units automatically separated into their component securities prior to or upon closing of the Business Combination and, as a result, no longer trade as a separate security.
Presentation of Financial and Operating Data
As a result of the Business Combination, we are the acquirer for accounting purposes, and CRP is the acquiree and accounting Predecessor. Our financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. We are the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination on October 11, 2016.
Organizational Structure
The following diagram illustrates the current ownership structure of the company:
ORGCHARTFONT.JPG
 
(1)
The Company intends to hold a special meeting at which its stockholders will vote on the issuance of the Class A Common Shares underlying the shares of Series B Preferred Stock.
(2)
CRD, one of the Centennial Contributors, also owns one share of our Series A Preferred Stock, par value $0.0001 per share (the “Series A Preferred Stock”), which does not have any voting rights (other than the right to nominate and elect one director to our board of directors) or rights with respect to dividends but is entitled to preferred distributions in liquidation in the amount of $0.0001 per share.

9

Table of Contents

Our Business
Our only significant asset is our current ownership of an approximate 92% membership interest in CRP. We are an independent oil and natural gas company focused on the development 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 properties consist of large, contiguous acreage blocks in Reeves, Ward and Pecos counties in West Texas.
Our principal business objective is to increase shareholder value by building a premier development company focused on horizontal drilling in the Delaware Basin. We intend to grow our production and oil and natural gas reserves by developing our acreage in Ward and Reeves Counties with an increased focus on optimizing completions, improving drilling results and drilling extended laterals. We also intend to grow our production and reserves through acquisitions that meet our strategic and financial objectives.
Our Properties
As of December 31, 2016 , our portfolio included 106 operated producing horizontal wells. The horizontal wells span an area approximately 45 miles long by 20 miles wide where we have established commercial production in five distinct zones: the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C. As a result, we have broadly appraised this acreage across various geographic areas and stratigraphic zones, which we expect will allow us to efficiently develop our drilling inventory with a focus on maximizing returns to our stockholders. In addition, we believe this acreage may be prospective for the 2nd and 3rd Bone Spring shales and Avalon shale, where other operators have experienced drilling success near our acreage.
As of December 31, 2016 , we have leased or acquired approximately 76,067 net acres, approximately 85% of which we operate. Our acreage is predominantly located in the southern portion of the Delaware Basin, where production and reserves typically contain a higher percentage of oil and natural gas liquids and a correspondingly lower percentage of natural gas compared to the northern area of the Delaware Basin. After temporarily suspending drilling activity at the end of March 2016 to preserve capital prior to the Business Combination, we added one horizontal rig in June 2016, a second horizontal rig in September 2016 and a third horizontal rig in October 2016. After closing the Silverback Acquisition on December 28, 2016, we had four rigs operating. During 2016, we placed ten gross operated horizontal wells on production. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus on optimizing completions, improving drilling results and managing costs.
Proved Oil and Gas Reserves
The table below presents information with respect to the estimates of our net proved reserves as of December 31, 2016 (Successor) , December 31, 2015 (Predecessor) and December 31, 2014 (Predecessor) . We engage Netherland, Sewell & Associates, Inc. (“NSAI”) to prepare our estimated net proved reserves. 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 for each year was adjusted for quality, transportation fees and a regional price differential. For gas volumes, the average Henry Hub spot price for each year 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 $38.49 per barrel of oil, $14.59 per barrel of NGL and $0.98 per Mcf of gas as of December 31, 2016 (Successor) , $41.85 per barrel of oil, $13.94 per barrel of NGL and $1.71 per Mcf of gas as of December 31, 2015 (Predecessor) , and $84.94 per barrel of oil, $22.70 per barrel of NGL and $4.70 per Mcf of gas as of December 31, 2014 (Predecessor) .
Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. PV-10 shown in the following table is not intended to represent the current market value of our estimated proved reserves. The actual quantities and present value of our estimated proved reserves may be more or less than we have estimated. The following table should be read along with Part I, Item 1A. Risk Factors in this annual report.
The following table summarizes estimated proved reserves, PV-10, and standardized measure of discounted future cash flows as of December 31, 2016 (Successor) , December 31, 2015 (Predecessor) , and December 31, 2014 (Predecessor) :

10

Table of Contents

 
Successor
 
 
Predecessor
 
December 31, 2016
 
 
December 31, 2015
 
December 31, 2014
Proved developed reserves:
 
 
 
 
 
 
Oil (MBbls)
14,551

 
 
9,347

 
8,026

Natural gas (MMcf)
42,190

 
 
12,711

 
11,959

NGL (MBbls)
3,618

 
 
1,603

 
766

Total (MBoe)(1)
25,200

 
 
13,068

 
10,786

Proved undeveloped reserves:
 
 
 
 
 
 
Oil (MBbls)
31,914

 
 
13,852

 
11,823

Natural gas (MMcf)
106,154

 
 
19,731

 
15,455

NGL (MBbls)
8,152

 
 
2,248

 
785

Total (MBoe)(1)
57,759

 
 
19,389

 
15,184

Total proved reserves:
 
 
 
 
 
 
Oil (MBbls)(1)
46,466

 
 
23,199

 
19,850

Natural gas (MMcf)(1)
148,344

 
 
32,442

 
27,414

NGL (MBbls)(1)
11,770

 
 
3,851

 
1,551

Total (MBoe)(1)
82,959

 
 
32,457

 
25,970

 
 
 
 
 
 
 
Proved developed reserves %
30
%
 
 
40
%
 
42
%
Proved undeveloped reserves %
70
%
 
 
60
%
 
58
%
 
 
 
 
 
 
 
Reserve data (in millions):
 
 
 
 
 
 
Proved developed PV-10
$
242.1

 
 
$
141.4

 
$
299.2

Proved undeveloped PV-10
185.4

 
 
4.1

 
71.2

Total proved PV-10
$
427.5

 
 
$
145.5

 
$
370.4

Standardized measure of discounted future net cash flows
$
375.1

 
 
$
135.1

 
$
365.9


(1)
Totals may not sum or calculate due to rounding.
Proved Undeveloped Reserve s
As of December 31, 2016 (Successor) , total estimated proved undeveloped reserves (“PUDs”) were 31,914 MBbls of oil, 106,154 MMcf of natural gas and 8,152 MBbls of NGLs, for a total of 57,759 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
Changes in PUDs that occurred during 2016 were primarily due to (i) an increase of approximately 14,773 MBoe attributable to extensions resulting from strategic drilling of wells delineating our acreage position; (ii) the conversion of approximately 2,112 MBoe from proved undeveloped into proved developed reserves; (iii) a revision in performance of approximately 2,488 MBoe due to improved results in completion techniques and adjustments of natural gas and NGL treatment through the gas plants; and (iv) an increase of 23,221 MBoe in proved undeveloped reserves mainly due to the Silverback Acquisition.
During 2016, we spent $22.9 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, 2016 , 854 MBoe of our total proved reserves were classified as proved developed non-producing (“PDNP”).
Preparation of Reserves Estimates
Evaluation and Review of Proved Reserves . Our historical proved reserve estimates as of December 31, 2016, 2015 and 2014 were prepared based on reports by NSAI. NSAI is a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. NSAI does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Neil H. Little and Mr. Mike K. Norton. Mr. Little, a

11

Table of Contents

Licensed Professional Engineer in the State of Texas (No. 117966), has been practicing consulting petroleum engineering at NSAI since 2011 and has over 9 years of prior industry experience. He graduated from Rice University in 2002 with a Bachelor of Science Degree in Chemical Engineering and from University of Houston in 2007 with a Master of Business Administration Degree. Mr. Norton, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441), has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers 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. He is a petroleum engineer with 37 years of reservoir and operations experience.
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, 2016, 2015 and 2014 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: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) 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 proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our properties, due to the mature nature of the properties targeted for development and an abundance of subsurface control data.
Production
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:

12

Table of Contents

 
Successor
 
 
Predecessor
 
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
 
Year Ended December 31,
 
 
 
 
2015
 
2014
Production data:
 
 
 
 
 
 
 
 
Oil (MBbls)
523

 
 
1,584

 
1,830

 
1,428

Natural gas (MMcf)
1,113

 
 
2,660

 
3,058

 
2,112

NGLs (MBbls)
96

 
 
253

 
331

 
235

Total (MBoe)
805

 
 
2,280

 
2,671

 
2,015

Average realized prices (excluding effect of hedges):
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
46.49

 
 
$
37.74

 
$
42.43

 
$
80.50

Natural gas (per Mcf)
3.10

 
 
2.27

 
2.60

 
4.58

NGL (per Bbl)
20.36

 
 
12.98

 
14.66

 
30.64

Per BOE
$
36.92

 
 
$
30.31

 
$
33.87

 
$
65.42

Production costs per Boe:
 
 
 
 
 
 
 
 
Lease operating expenses
$
4.40

 
 
$
4.84

 
$
7.93

 
$
8.78

Severance and ad valorem taxes
2.03

 
 
1.62

 
1.88

 
3.41

Transportation, processing, gathering and other operating expenses
2.72

 
 
2.01

 
2.15

 
2.37

Contract termination and rig stacking

 
 

 
0.89

 

Productive Wells
As of December 31, 2016 , we owned an approximate 67% average working interest in 199 gross ( 133 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.
Acreage
The following table sets forth information as of December 31, 2016 relating to our leasehold acreage. Developed acreage consists of acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
Developed Acreage
 
Undeveloped Acreage
 
Total Acreage
Gross(1)
 
Net(2)
 
Gross(1)
 
Net(2)
 
Gross(1)
 
Net(2)
10,800

 
10,000

 
113,158

 
66,067

 
123,958

 
76,067

 
(1)
A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(2)
A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
The following table sets forth the gross and net undeveloped acreage, as of December 31, 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:
2017
 
2018
 
2019
 
2020
 
2021
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net(1)
 
Gross
 
Net(1)
19,942

 
12,440

 
23,748

 
10,420

 
16,528

 
12,071

 

 
102

 

 
30

 
(1)
Expiring net acreage may be greater than expiring gross acreage when multiple undivided interests in the same gross acreage expire at different times.

13

Table of Contents

Drilling Results
The following table sets forth the results of our drilling activity, as defined by wells placed on production, for the periods indicated. 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.
 
Successor
 
 
Predecessor
 
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
 
Year Ended December 31,
 
 
 
 
2015
 
2014
 
Gross
 
Net
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development Wells:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Productive(1)
5.0

 
2.5

 
 
10.0

 
7.0

 
16.0

 
12.4

 
36.0

 
26.8

Dry

 

 
 

 

 

 

 

 

 
5.0

 
2.5

 
 
10.0

 
7.0

 
16.0

 
12.4

 
36.0

 
26.8

Exploratory Wells:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Productive(1)

 

 
 

 

 

 

 

 

Dry

 

 
 

 

 

 

 

 

 

 

 
 

 

 

 

 

 

Total
5.0

 
2.5

 
 
10.0

 
7.0

 
16.0

 
12.4

 
36.0

 
26.8

 
(1)
Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and 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 report.
Marketing and Customers
We market the majority of our production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our oil, natural gas and NGL production to purchasers at market prices. We sell all of our natural gas and NGLs under contracts with terms of greater than twelve months and all of our oil under contracts with terms of less than twelve months.

14

Table of Contents

We normally sell production to a relatively small number of customers, as is customary in our business. For the year ended December 31, 2016 , sales to Plains Marketing, LP (“Plains”), Shell Trading (US) Company, and Permian Transport and Trading accounted for 48% , 22% , and 11% , respectively, of the total revenue. For the years ended December 31, 2015 and December 31, 2014 , we only had one major customer, Plains, which accounted for 64% and 78% , respectively, of total revenue. During these periods, no other purchaser accounted for 10% or more of our revenue. The loss of any of our major purchasers 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 any major 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.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.
Transportation
During the initial development of our fields, we consider all gathering and delivery infrastructure options in the areas of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The purchaser then transports the oil by truck or pipeline to a tank farm, another pipeline or a refinery. 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.
Seasonality of Business
Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.
Oil and Natural Gas Leases
The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties as of December 31, 2016 generally range from 20% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 80%.
Regulation of the Oil and Natural Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the development and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and

15

Table of Contents

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.
Regulation of Production of Oil and Natural Gas
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in Texas, which regulates drilling and operating activities by, among other things, requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation of Sales and Transportation of Oil
Sales of oil, condensate and NGLs from our producing wells are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future.
Our sales of oil are affected by the availability, terms and conditions and cost of transportation services. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates the transportation in interstate commerce of crude oil, petroleum products, NGLs and other forms of liquid fuel under the Interstate Commerce Act.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We rely on third-party pipelines systems to transport the majority of crude oil produced by ours wells. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other oil producers and marketers with which we compete.
Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA, and culminated in

16

Table of Contents

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

17

Table of Contents

rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers and marketers with which we compete.
Regulation of Environmental and Occupational Safety and Health Matters
Our oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.
The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous Substances and Waste Handling
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.
The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, from time to time various environmental groups have challenged the EPA’s exemption of certain oil and gas wastes from RCRA. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial 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.

18

Table of Contents

We currently own, lease or operate numerous properties that have been used for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.
Water Discharges
The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In September 2015, the EPA and the Corps issued new rules defining the scope of the EPA’s and the Corps’ jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands. To the extent the rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of the Clean Water Act, and implementation of the rule has been stayed pending resolution of the court challenge. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.
Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. We believe that we maintain all required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof. We are currently undertaking a review of recently acquired oil properties to determine the need for new or updated SPCC plans and, 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.
Air Emissions
The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. More recently, in May 2016,

19

Table of Contents

the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.
Regulation of GHG Emissions
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The agreement was signed in April 2016, and entered into force in November 2016. The United States is one of over 70 nations having ratified or otherwise consented to be bound by the agreement. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, 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 Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming struck down this rule. The BLM has appealed this decision. The appeal remains pending. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the

20

Table of Contents

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.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.
ESA and Migratory Birds
The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government recently issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
OSHA
We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.
Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.
We have not experienced any material adverse effect from compliance with environmental requirements; however, there is no assurance that this will continue. We have not incurred any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2016, nor do we expect to incur any such expenditures in 2017.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this

21

Table of Contents

insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.
Employees
As of December 31, 2016 , we had 57 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.
Offices
Our principal executive offices are located at 1401 Seventeenth Street, Suite 1000, Denver, Colorado 80202, and our telephone number is (720) 441-5515. We also lease office space in Midland, Texas, Sugar Land, Texas and Pecos, Texas.
Available Information
Our internet website address is www.cdevinc.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. Information on our website is not incorporated by reference into this report and should not be considered part of this document.
The public may also read and copy materials we file with the SEC at the SEC’s Public Reference Room, which is located at 100 F Street, NE, Room 1580, Washington, DC 20549. You can obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC at www.sec.gov.

22

Table of Contents

ITEM 1A. RISK FACTORS
The nature of our business activities subjects us to certain hazards and risks. The following risks and uncertainties, together with other information set forth in this annual report on Form 10-K, should be carefully considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties presently unknown to us or currently deemed immaterial also may impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, our financial condition, and the results of our operations, which in turn could negatively impact the value of our securities.
Our only significant asset is our current ownership of an approximate 92% membership interest in CRP. Distributions from CRP may not be sufficient to allow us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations.
We have no direct operations and no significant assets other than our current ownership of an approximate 92% membership interest in CRP. We will depend on CRP for distributions, loans and other payments to generate the funds necessary to meet our financial obligations or to pay any dividends with respect to our Class A Common Stock. Subject to certain restrictions, CRP generally will be required to (i) make pro rata distributions to its members, including us, in an amount at least sufficient to allow us to pay our taxes and (ii) reimburse us for certain corporate and other overhead expenses. However, legal and contractual restrictions in agreements governing future indebtedness of CRP, as well as the financial condition and operating requirements of CRP may limit our ability to obtain cash from CRP. The earnings from, or other available assets of, CRP may not be sufficient to pay dividends or make distributions or loans to enable us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations.
Oil, natural gas and NGL prices are volatile. A sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The prices we receive for our oil, natural gas and NGLs production heavily influence our revenue, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, natural gas and NGLs and market uncertainty. Historically, oil, natural gas and NGL prices have been volatile. For example, during the period from January 1, 2014 through December 31, 2016, the WTI spot price for oil has declined from a high of $107.95 per Bbl on June 20, 2014 to $26.19 per Bbl on February 11, 2016 , and the Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016 . Likewise, NGLs, which are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:
worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and NGLs;
the price and quantity of foreign imports of oil, natural gas and NGLs;
political and economic conditions in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia;
actions of the Organization of the Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production controls;
the level of global exploration, development and production;
the level of global inventories;
prevailing prices on local price indexes in the area in which we operate;
the proximity, capacity, cost and availability of gathering and transportation facilities;
localized and global supply and demand fundamentals and transportation availability;
the cost of exploring for, developing, producing and transporting reserves;
weather conditions and other natural disasters;
technological advances affecting energy consumption;
the price and availability of alternative fuels;
expectations about future commodity prices; and

23

Table of Contents

U.S. federal, state and local and non-U.S. governmental regulation and taxes.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Compared to 2014, our realized oil price for 2015 fell 47% to $42.43 per barrel, and further decreased in 2016 to $39.91 per barrel. Similarly, our realized natural gas price for 2015 dropped 43% to $2.60 per Mcf and our realized price for NGLs declined 52% to $14.66 per barrel. In 2016 , our realized price for natural gas was $2.52 per Mcf and our realized price for NGLs was $15.01 per barrel. If the prices of oil and natural gas continue at current levels or decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.
In addition, 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:
the prices at which our production is sold;
our proved reserves;
the level of hydrocarbons we are able to produce from existing wells;
our ability to acquire, locate and produce new reserves;
the levels of our operating expenses; and
CRP’s ability to borrow under its revolving credit facility and the ability to access the capital markets.
If our revenues or the borrowing base under CRP’s revolving credit facility decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under CRP’s revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties. This, in turn, could lead to a decline in our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include the following:
landing a wellbore in the desired drilling zone;

24

Table of Contents

staying in the desired drilling zone while drilling horizontally through the formation;
running our casing the entire length of the wellbore; and
being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that we face while completing wells include the following:
the ability to fracture stimulate the planned number of stages;
the ability to run tools the entire length of the wellbore during completion operations; and
the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as anticipated, and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.
Our decisions to develop or purchase prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “ Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from wastewater disposal, emission of greenhouse gases (“GHGs”) and limitations on hydraulic fracturing;
pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment and qualified personnel or in obtaining water and sand for hydraulic fracturing activities;
equipment failures, accidents or other unexpected operational events;
lack of available gathering facilities or delays in construction of gathering facilities;
lack of available capacity on interconnecting transmission pipelines;
adverse weather conditions;
issues related to compliance with environmental regulations;
environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
declines in oil and natural gas prices;
limited availability of financing at acceptable terms;
title problems; and
limitations in the market for oil and natural gas.

25

Table of Contents

The Silverback Acquisition involves risks associated with acquisitions and integrating acquired properties, including the potential exposure to significant liabilities, and the intended benefits of the Silverback Acquisition may not be realized.
The Silverback Acquisition involves risks associated with acquisitions and integrating acquired properties into existing operations, including that:
our senior management’s attention may be diverted from the management of daily operations to the integration of the properties acquired in the Silverback Acquisition;
we could incur significant unknown and contingent liabilities for which we have limited or no contractual remedies or insurance coverage;
the properties acquired in the Silverback Acquisition may not perform as well as we anticipate;
unexpected costs, delays and challenges may arise in integrating the properties acquired in the Silverback Acquisition into our existing operations; and
we may need to hire additional staff, devote additional resources and contract additional rigs to integrate the properties acquired in the Silverback Acquisition.
Even if we successfully integrate the properties acquired in the Silverback Acquisition into our operations, it may not be possible to realize the full benefits we anticipate or we may not realize these benefits within the expected timeframe. If we fail to realize the benefits we anticipate from the Silverback Acquisition, our business, results of operations and financial condition may be adversely affected.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. CRP’s credit agreement currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
Restrictions in CRP’s existing and future debt agreements could limit our growth and ability to engage in certain activities.
CRP’s credit agreement contains a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:
incur additional indebtedness;
make loans to others;
make investments;
merge or consolidate with another entity;
make certain payments;
hedge future production or interest rates;
incur liens;
sell assets; and
engage in certain other transactions without the prior consent of the lenders.

26

Table of Contents

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 December 31, 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 Silverback Acquisition, CRP entered into an amendment to its credit agreement to, among other things, increase the borrowing base from $200.0 million to $250.0 million. The next scheduled borrowing base redetermination is expected in the spring of 2017.
In the future, we may not be able to access adequate funding under CRP’s revolving credit facility (or a replacement facility) as a result of a decrease in the borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, CRP could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service CRP’s indebtedness.
Our derivative activities could result in financial losses or could reduce our earnings.
We enter into derivative instrument contracts for a portion of our oil and natural gas production. As of December 31, 2016 , we had entered into hedging contracts through December 2018 covering a total of 712 MBbls of our projected oil production and 1,460 BBtu of our projected natural gas production. In addition, as of December 31, 2016 , we had entered into basis swaps covering a total of 128 MBbls of our projected oil production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
production is less than the volume covered by the derivative instruments;
the counterparty to the derivative instrument defaults on its contractual obligations;
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of 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.

27

Table of Contents

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, 2016, and related standardized measure were calculated under rules of the SEC using twelve-month trailing average benchmark prices of $39.25 per barrel of oil (WTI) and $2.48 per MMBtu (Henry Hub spot), which may be substantially higher or lower than the available spot prices in 2017. 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.
As of December 31, 2016 , we have leased or acquired approximately 76,067 net acres, approximately 85% of which we operate. As of December 31, 2016 , we were the operator on 1,230 of our 1,951 identified gross horizontal drilling locations. We acquired approximately 35,500 net acres in the Silverback Acquisition, approximately 90% of which we operate. Of the net acres acquired, 1,250 net acres are subject to consents to assign, which are expected to be assigned in the first quarter of 2017. 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:
the timing and amount of capital expenditures;
the operator’s expertise and financial resources;
the approval of other participants in drilling wells;
the selection of technology; and
the rate of production of reserves, if any.
This limited ability to exercise control over the operations and associated costs of some of our drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activities.

28

Table of Contents

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 December 31, 2016 , we had identified 1,951 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 December 31, 2016 , approximately 50% of our total net acreage (approximately 51% of our operated net acreage in Reeves and Ward counties) was held by production. Of the net acreage acquired in the Silverback Acquisition, approximately 37% was held by production. 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, 2016 , all of our total estimated proved reserves were attributable to properties located in this area.

29

Table of Contents

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, 2016 , 70% 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 December 30, 2016, the WTI spot price for crude oil was $53.75 per barrel and the Henry Hub spot price for natural gas was $3.71 per MMBtu, representing decreases of 50% and 54% , respectively, from the high of $107.95 per barrel of oil and $8.15 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

30

Table of Contents

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 small number of significant purchasers for the sale of most of our oil, natural gas and NGL production.
We normally sell production to a relatively small number of customers, as is customary in our business. For the year ended December 31, 2016 , sales to Plains Marketing, LP (“Plains”), Shell Trading (US) Company, and Permian Transport and Trading accounted for 48% , 22% , and 11% , respectively, of the total revenue. For the years ended December 31, 2015 and December 31, 2014 , we only had one major customer, Plains, which accounted for 64% and 78% , respectively, of total revenue. The loss of any of our major purchasers 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 any major 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.
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:

31

Table of Contents

environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;
abnormally pressured formations;
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse; fire, explosions and ruptures of pipelines;
personal injuries and death;
natural disasters; and
terrorist attacks targeting oil and natural gas related facilities and infrastructure.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
injury or loss of life;
damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties; and
repair and remediation costs.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:
unexpected drilling conditions;
title problems;
pressure or lost circulation in formations;
equipment failure or accidents;
adverse weather conditions;
compliance with environmental and other governmental or contractual requirements; and
increases in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we will be able to identify attractive acquisition opportunities. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to

32

Table of Contents

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, 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.

33

Table of Contents

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce, while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require additional personnel time to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. The United States is one of over 70 nations that has ratified or otherwise consented to be bound by the agreement. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, 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.

34

Table of Contents

Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in 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

35

Table of Contents

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:
increased responsibilities for our executive level personnel;
increased administrative burden;
increased capital requirements; and
increased organizational challenges common to large, expansive operations.
Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information of CRP included elsewhere in this prospectus is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. At December 31, 2016 , we had no outstanding debt. However, for example, if our entire credit facility borrowing base of $250.0 million was outstanding at December 31, 2016 , a 1.0% increase in interest rates would result in an increase in annual interest expense of approximately $2.5 million, assuming the $250.0 million of debt was outstanding for the full year. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
We may be subject to risks in connection with acquisitions of properties.
The successful acquisition of producing properties requires an assessment of several factors, including:
recoverable reserves;
future oil and natural gas prices and their applicable differentials;
operating costs; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
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. Congress has previously considered 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

36

Table of Contents

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

37

Table of Contents

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:
changes in the valuation of our deferred tax assets and liabilities;
expected timing and amount of the release of any tax valuation allowances;
tax effects of stock-based compensation;
costs related to intercompany restructurings;
changes in tax laws, regulations or interpretations thereof; or
lower than anticipated future earnings in jurisdictions where we have lower statutory tax rates and higher than anticipated future earnings in jurisdictions where we have higher statutory tax rates.
In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.

38

Table of Contents

Risks Related to Our Securities and Capital Structure
The market price of our securities may decline.
Fluctuations in the price of our securities could contribute to the loss of all or part of your investment. Prior to the closing of the Business Combination, trading in our Class A Common Stock and Public Warrants had been limited. If an active market for our securities develops and continues, the trading price of our securities could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Any of the factors listed below could have a material adverse effect on your investment and our securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of our securities may not recover and may experience a further decline.
Factors affecting the trading price of our securities may include:
actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to us;
changes in the market’s expectations about our operating results;
success of competitors;
our operating results failing to meet the expectation of securities analysts or investors in a particular period;
changes in financial estimates and recommendations by securities analysts concerning us or its markets in general;
operating and stock price performance of other companies that investors deem comparable to us;
our ability to market new and enhanced products on a timely basis;
changes in laws and regulations affecting our business;
commencement of, or involvement in, litigation involving us;
changes in our capital structure, such as future issuances of securities or the incurrence of additional debt;
the volume of securities available for public sale;
any major change in our board or management;
sales of substantial amounts of our securities by our directors, executive officers or significant stockholders or the perception that such sales could occur; and
general economic and political conditions such as recession; interest rate, fuel price, and international currency fluctuations; and acts of war or terrorism.
Many of the factors listed above are beyond our control. In addition, broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general, and NASDAQ have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of these stocks, and of our Class A Common Stock and Public Warrants which trade on NASDAQ, may not be predictable. A loss of investor confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to the Company could depress the price of our securities regardless of our business, prospects, financial conditions or results of operations. A decline in the market price of our securities also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.
If securities or industry analysts do not publish or cease publishing research or reports about us, our business, or our market, or if they change their recommendations regarding our securities adversely, the price and trading volume of our securities could decline.
The trading market for our securities will be influenced by the research and reports that industry or securities analysts may publish about us, our business, our market, or our competitors. Securities and industry analysts do not currently, and may never, publish research on us. If no securities or industry analysts commence coverage of us, our stock price and trading volume would likely be negatively impacted. If any of the analysts who may cover us change their recommendation regarding our securities adversely, or provide more favorable relative recommendations about our competitors, the price of our securities would likely decline. If any analyst who may cover us were to cease coverage of us or fail to regularly publish reports on it, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.
Riverstone and its affiliates own a significant percentage of our outstanding voting common stock.
Riverstone and its affiliates, including our Sponsor, beneficially own approximately 44.0% of our voting common stock and, upon the conversion of our Series B Preferred Stock, par value $0.0001 per share (the “Series B Preferred Stock”), will

39

Table of Contents

beneficially own approximately 49.96% of our voting common stock. As long as Riverstone and its affiliates, including our Sponsor, own or control a significant percentage of outstanding voting power, they will have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of directors and the size of our board of directors, any amendment of our second amended and restated certificate of incorporation (the “Charter”) or amended and restated bylaws (the “Bylaws”), or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets.
The interests of Riverstone and its affiliates, including our Sponsor, may not align with the interests of our other stockholders. Our Sponsor is in the business of making investments in companies and may acquire and hold interests in businesses that compete directly or indirectly with us. Riverstone and its affiliates, including our Sponsor, may also pursue acquisition opportunities that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us. In addition, our Charter provides that we renounce any interest or expectancy in the business opportunities of our officers and directors and their respective affiliates and each such party shall not have any obligation to offer us those opportunities unless presented to one of our directors or officers in his or her capacity as a director or officer.
We are no longer a “controlled company” within the meaning of the NASDAQ listing rules, and will not be able to take advantage of exemptions from certain corporate governance requirements.
Riverstone and its affiliates, including our Sponsor, no longer control a majority of our outstanding voting common stock. After the conversion of our Series B Preferred Stock, Riverstone will not own over 50.0% of our voting common stock. As a result, we are no longer a “controlled company” within the meaning of the NASDAQ listing rules, and will not be able to take advantage of exemptions from certain corporate governance requirements. Under the NASDAQ listing rules, a company of which more than 50% of the voting power is held by an individual, group or another company is a “controlled company” and is exempt from certain corporate governance requirements, including, among others, the following:
a majority of its board of directors consist of independent directors (as defined under the NASDAQ corporate governance standards);
its nominating and corporate governance committee consists entirely of independent directors; and
the compensation of its executive officers be determined, or recommended to the board for determination, by a majority of independent directors in a vote by independent directors, or by a compensation committee comprised solely of independent directors.
Pursuant to the requirements of the NASDAQ listing rules, a majority of our board of directors must consist of independent directors within one year after we cease to be a controlled company. In addition, we must comply with the independent board committee requirements as they relate to the nominating and corporate governance and compensation committees on the following phase-in schedule: (1) one independent committee member at the time we cease to be a controlled company, (2) a majority of independent committee members within 90 days of the date we cease to be a controlled company and (3) all independent committee members within one year of the date we cease to be a controlled company. Our board of directors is not currently comprised of a majority of independent directors, and neither our nominating and corporate governance committee nor our compensation committee is currently comprised solely of independent directors. Accordingly, during the applicable phase-in periods provided for under the NASDAQ listing rules, you may not have the same protections afforded to stockholders of companies that are subject to all of the NASDAQ corporate governance standards.
Anti-takeover provisions contained in our Charter and 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:
no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates;
the exclusive right of our board of directors to elect a director to fill a vacancy created by the expansion of the board of directors or the resignation, death, or removal of a director, which prevents stockholders from being able to fill vacancies on our board of directors;
the ability of our board of directors to determine whether to issue shares of our preferred stock and to determine the price and other terms of those shares, including preferences and voting rights, without stockholder approval, which could be used to significantly dilute the ownership of a hostile acquirer;
a prohibition on stockholder action by written consent, which forces stockholder action to be taken at an annual or special meeting of our stockholders;

40

Table of Contents

the requirement that an annual meeting of stockholders may be called only by the chairman of the board of directors, the chief executive officer, or the board of directors, which may delay the ability of our stockholders to force consideration of a proposal or to take action, including the removal of directors;
limiting the liability of, and providing indemnification to, our directors and officers;
controlling the procedures for the conduct and scheduling of stockholder meetings;
providing that directors may be removed prior to the expiration of their terms by stockholders only for cause; and
advance notice procedures that stockholders must comply with in order to nominate candidates to our board of directors or to propose matters to be acted upon at a stockholders’ meeting, which may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of directors or otherwise attempting to obtain control of the Company.
These provisions, alone or together, could delay hostile takeovers and changes in control of the Company or changes in our board of directors and management.
As a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law (the “DGCL”), which prevents some stockholders holding more than 15% of our outstanding voting common stock from engaging in certain business combinations without approval of the holders of substantially all of our outstanding voting common stock. Any provision of our Charter or Bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their securities and could also affect the price that some investors are willing to pay for our securities.
The JOBS Act permits “emerging growth companies” like us to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies.
We qualify as an “emerging growth company” as defined in the JOBS Act. As such, we take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies for as long as we continue to be an emerging growth company, including (i) the exemption from the auditor attestation requirements with respect to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act, (ii) the exemptions from say-on-pay, say-on-frequency and say-on-golden parachute voting requirements and (iii) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. As a result, our stockholders may not have access to certain information they deem important. We will remain an emerging growth company until the earliest of (i) the last day of the fiscal year (a) following February 28, 2021, the fifth anniversary of our IPO, (b) in which we have total annual gross revenue of at least $1.0 billion or (c) in which we are deemed to be a large accelerated filer, which means the market value of our Class A Common Stock that is held by non-affiliates exceeds $700 million as of the last business day of our prior second fiscal quarter, and (ii) the date on which we have issued more than $1.0 billion in non-convertible debt during the prior three-year period.
In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the exemption from complying with new or revised accounting standards provided in Section 7(a)(2)(B) of the Securities Act as long as we are an emerging growth company. An emerging growth company can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies, but any such election to opt out is irrevocable. We have elected not to opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of our financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accountant standards used.
We cannot predict if investors will find our Class A Common Stock less attractive because we will rely on these exemptions. If some investors find our Class A Common Stock less attractive as a result, there may be a less active trading market for our Class A Common Stock and our stock price may be more volatile.
Non-U.S. holders may be subject to U.S. income tax with respect to gain on disposition of their Class A Common Stock.
We believe that we are a United States real property holding corporation (a “USRPHC”). As a result, Non-U.S. holders (defined below in the section entitled “Material U.S. Federal Income Tax Considerations”) that own (or are treated as owning under constructive ownership rules) more than a specified amount of our Class A Common Stock during a specified time period may be subject to U.S. federal income tax on a sale, exchange, or other disposition of such Class A Common Stock and may be required to file a U.S. federal income tax return. If you are a Non-U.S. holder, we urge you to consult your tax advisors regarding the tax consequences of such treatment.

41

Table of Contents

ITEM 1B.    UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we are a party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment-related disputes. We do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations, or liquidity.
ITEM 4. MINE SAFETY DISCLOSURE
Not applicable.

42

Table of Contents

PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our 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 was quoted under the symbol “SRAQ.” The following table sets forth, for the calendar quarter indicated, the high and low sales price per share of Class A Common Stock as reported on NASDAQ for the periods presented:
 
Class A Common Stock
(CDEV)
 
High
 
Low
2016:
 
 
 
Fourth Quarter
$
20.97

 
$
13.31

Third Quarter
16.10

 
9.65

Second Quarter(1)
10.70

 
9.65

First Quarter(2)
N/A

 
N/A

 
(1)
Beginning on April 15, 2016.
(2)
Since the Class A Common Stock commenced separate trading on April 15, 2016, there is no information presented for the Class A Common Stock for the first quarter of 2016.
As of March 7, 2017 , there were 254 holders of record of our Class A Common Stock.
Dividend Policy
We have not paid any cash dividends on our Class A Common Stock or Class C Common Stock to date. Our board of directors may from time to time consider whether or not to institute a dividend policy. It is our present intention to retain any earnings for use in our business operations and, accordingly, we do not anticipate the board of directors declaring any dividends in the foreseeable future.
ITEM 6. SELECTED FINANCIAL DATA
The following data should be read in conjunction with  Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations , which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our consolidated and combined financial statements included in this report.
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 Part II, Item 7. 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 in Part II, Item 8. Financial Statements and Supplementary Data .




43

Table of Contents

 
Successor
 
 
Predecessor
 
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
 
Year Ended December 31,
(in thousands, except per share, production and per BOE data)
 
 
 
2015
 
2014
 
2013
Statements of Operations Data:
 
 
 
 
 
 
 
 
 
 
Total revenues
$
29,717

 
 
$
69,116

 
$
90,460

 
$
131,825

 
$
71,974

Net (loss) income attributable to Centennial Resource Development, Inc.
(8,081
)
 
 
(218,724
)
 
(38,325
)
 
17,790

 
3,618

Income (loss) per share:
 
 
 
 
 
 
 
 
 
 
Basic
$
(0.05
)
 
 
 
 
 
 
 
 
 
Diluted
$
(0.05
)
 
 
 
 
 
 
 
 
 
Production Data:
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
523

 
 
1,584

 
1,830

 
1,428

 
713

Natural gas (MMcf)
1,113

 
 
2,660

 
3,058

 
2,112

 
797

NGLs (MBbls)
96

 
 
253

 
331

 
235

 
98

Total (MBoe)
805

 
 
2,280

 
2,671

 
2,015

 
944

Expenses per Boe:
 
 
 
 
 
 
 
 
 
 
Lease operating expenses
$
4.40

 
 
$
4.84

 
$
7.93

 
$
8.78

 
$
20.24

Severance and ad valorem taxes
2.03

 
 
1.62

 
1.88

 
3.41

 
4.40

Transportation, processing, gathering and other operating expense
2.72

 
 
2.01

 
2.15

 
2.37

 
1.37

Depreciation, depletion, amortization and accretion of asset retirement obligations
18.48

 
 
27.62

 
33.73

 
34.30

 
31.02

Abandonment expense and impairment of unproved properties

 
 
1.12

 
2.85

 
9.94

 
9.07

Exploration
1.05

 
 

 
0.03

 

 

Contract termination and rig stacking

 
 

 
0.89

 

 

General and administrative expenses
17.04

 
 
11.22

 
5.32

 
15.73

 
17.84

Cash Flows Data:
 
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
9,410

 
 
$
51,740

 
$
68,882

 
$
97,248

 
$
13,416

Net cash used by investing activities
(1,749,733
)
 
 
(101,434
)
 
(198,635
)
 
(163,380
)
 
(136,517
)
Net cash provided by financing activities
1,874,268

 
 
47,926

 
118,504

 
36,966

 
118,742

 
Successor
 
 
Predecessor
(in thousands)
December 31, 2016
 
 
December 31, 2015
 
December 31, 2014
 
December 31, 2013
Balance Sheet Data:
 
 
 
 
 
 
 
 
Total assets
$
2,651,642

 
 
$
616,295

 
$
615,769

 
$
472,085

Long-term debt

 
 
138,649

 
129,568

 
29,000

Dividends per share

 
 

 

 


44

Table of Contents

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated and combined financial statements and related notes in “Part II, Item 8. Financial Statements and Supplementary Data.”  The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Please see “Cautionary Statement Concerning Forward-Looking Statements” and “Part I, Item 1A. Risk Factors” in this Report.
Overview
We are an independent oil and natural gas company focused on the development 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.
We have no direct operations and no significant assets other than our current ownership of an approximate 92% membership interest in CRP. CRP is considered our accounting Predecessor and, accordingly, the following financial results and discussion and analysis reflect the results of CRP prior to the closing of the Business Combination.
Silver Run Business Combination
Centennial Resource Development, Inc. (the “Company,” “Centennial,” “we,” “us,” or “our”) was originally incorporated in Delaware on November 4, 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.
On February 29, 2016, we consummated our initial public offering of Units each consisting of one share of Class A Common Stock and one-third of one Public Warrant. On October 11, 2016, we consummated the acquisition of approximately 89% of the outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company (“CRP” and such acquisition, the “Business Combination”).
The application of acquisition accounting for the Business Combination significantly affected certain assets, liabilities, and expenses. As a result, financial information as of December 31, 2016 and in the period October 11, 2016 through December 31, 2016 is not necessarily comparable to CRP’s predecessor financial information.
Presentation of Financial and Operating Data
As a result of the Business Combination, we are the acquirer for accounting purposes, and CRP is the acquiree and accounting Predecessor. Our financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. We are the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination on October 11, 2016.
For all periods ending on or before October 15, 2014 and for all dates on or before October 15, 2014, the historical financial results contained herein reflect the combined results of (i) CRP and (ii) Celero Energy Company, LP, a Delaware limited partnership ("Celero"), which was formed in 2006 to focus on the development and acquisition of oil and natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas. On October 15, 2014, Celero conveyed substantially all of its oil and natural gas properties and other assets to CRP in exchange for membership interests in CRP, and as a result, subsequent to October 15, 2014, the historical financial results contained herein reflect the results of CRP. Except as the context otherwise requires, references in the following discussion to the "Company," "we," "our" or "us" with respect to periods prior to the closing of the Business Combination are to CRP and its operations prior to the closing of the Business Combination.
Recent Developments
Silverback Acquisition
On December 28, 2016, we completed the acquisition (the “Silverback Acquisition”) of leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and Silverback Operating, LLC (collectively, “Silverback”) for a cash purchase price of approximately $855.0 million, subject to customary purchase price adjustments. The assets acquired from Silverback include 31 operated producing horizontal wells and approximately 35,500 net acres that directly offset our existing acreage in Reeves County, Texas. We operate approximately 90% of, and have an approximate 90% working interest in this acreage. Of the net acres acquired, 1,250 net acres are subject to consents to assign, which are expected to be

45

Table of Contents

assigned in the first quarter of 2017. The Wolfcamp A and B are producing horizons on this acreage and we believe that this acreage may be prospective for the Wolfcamp C and Avalon and Bone Spring shale formations.
Issuance of Class A Common Stock and Preferred Stock in Private Placements
In connection with the Silverback Acquisition, we issued and sold in private placements (i) 3,473,590 shares of Class A Common Stock and 104,400 shares of Series B Preferred Stock to the Riverstone Purchasers and (ii) 33,012,380 shares of our Class A Common Stock to certain other investors, resulting in gross proceeds of approximately $910.0 million. We used the proceeds from the private placements to fund the cash consideration for the Silverback Acquisition and expect to use any remaining proceeds for general corporate purposes.
The shares of Series B Preferred Stock are automatically convertible into shares of our Class A Common Stock on a 250-to-1 basis (subject to certain adjustments) at such time as we receive stockholder approval for the issuance of such shares of Class A Common Stock in compliance with NASDAQ listing rules (“Stockholder Approval”). We intend to call a special meeting of our stockholders in order to receive such approval. For a more detailed description of the Series B Preferred Stock, refer to Note 7—Shareholders' and Owners' Equity to the Consolidated and Combined Financial Statements in Part II, Item 8. Financial Statements and Supplementary Data in this annual report.
Credit Agreement Amendment
On December 28, 2016, in connection with the closing of the Silverback Acquisition, CRP entered into an amendment to its credit agreement to, among other things, increase the borrowing base thereunder from $200.0 million to $250.0 million.
Redemption of Public Warrants
On March 1, 2017, the Company delivered a notice of redemption of the Public Warrants, announcing its intention to redeem any unexercised and outstanding Public Warrants on March 31, 2017 for $0.01 per Public Warrant. As permitted under the warrant agreement that provides the terms of the Public Warrants, the notice of redemption requires all holders exercising their Public Warrants prior to March 31, 2017 to do so on a “cashless basis” and surrender their Public Warrants for a number of shares of Class A Common Stock equal to the product of the quotient equal to (i) the difference between $11.50 and $18.44 (the average last sale price of the Class A Common Stock for the ten trading days ending on February 24, 2017) divided by (ii) $18.44 , or approximately 0.376 , multiplied by the number of Public Warrants held by such holder, rounded down to the nearest whole share.  Assuming all warrants are exercised by holders, Centennial will issue approximately 6.27 million shares of Class A Common Stock to the Public Warrant holders, resulting in a share count of approximately 253 million shares outstanding, which includes Class A Common Stock shares, the shares of Series B Preferred Stock held by Riverstone (assuming conversion to Class A Common Stock on a 250-to-one basis), and the shares of Class C Common Stock held by the Centennial Contributors. The Private Placement Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees.
Market Conditions
The oil and gas industry is cyclical and commodity prices can be volatile. In the second half of 2014, oil prices began a rapid and significant decline as global and domestic supply began to outpace demand. During 2015 and 2016, global and domestic oil supply continued to outpace demand resulting in further deterioration in realized oil prices. In 2016, oil prices were volatile, and it is likely that oil prices will continue to fluctuate due to the ongoing global supply and demand imbalance, high inventories and geopolitical factors.
Our revenue, profitability and future growth are highly dependent on the prices we receives 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% to $42.43 per barrel, and our realized oil price for 2016 further decreased to $39.91 per barrel. Similarly, our realized natural gas price for 2015 dropped 43% to $2.60 per Mcf and our realized price for NGLs declined 52% to $14.66 per barrel. For 2016 , our realized price for natural gas was $2.52 per Mcf and our realized price for NGLs was $15.01 per barrel. Lower oil, natural gas and NGL prices may not only 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 our 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. 
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

46

Table of Contents

realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts on its oil and natural gas production;
production results;
lease operating expenses; and
Adjusted EBITDAX (1) .
 
(1)
Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States (“GAAP”). Please see "Non-GAAP Financial Measure" below for a reconciliation.
Sources of our Revenues
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. For the period from October 11, 2016, through December 31, 2016 (Successor) , oil sales, natural gas sales and NGL sales contributed 82% , 12% , and 7% , respectively, of our total revenues. For the period from January 1, 2016, through October 10, 2016 (Predecessor) , oil sales, natural gas sales and NGL sales contributed 87% , 9% and 5% , respectively of our total revenues. Our oil, natural gas and NGL revenues do not include the effects of derivatives for either period.
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 $0.5 million and a $1.6 million change in oil revenues for the periods from October 11, 2016, through December 31, 2016 (Successor) and January 1, 2016, through October 10, 2016 (Predecessor) , respectively. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.1 million and a $0.3 million change in our natural gas revenues for the periods from October 11, 2016, through December 31, 2016 (Successor) and January 1, 2016, through October 10, 2016 (Predecessor) , respectively. A $1.00 per barrel change in our realized NGL prices would have resulted in a $0.1 million and a $0.3 million change in NGL revenues for the periods from October 11, 2016, through December 31, 2016 (Successor) and January 1, 2016, through October 10, 2016 (Predecessor) , respectively.
The following table presents our average realized commodity prices, as well as the effects of derivative settlements.
 
Successor
 
 
Predecessor
 
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
 
Year Ended December 31,
 
 
 
 
2015
 
2014
Crude Oil (per Bbl):
 
 
 
 
 
 
 
 
Average NYMEX price
$
49.21

 
 
$
41.75

 
$
48.76

 
$
92.86

Average realized price, before the effects of derivative settlements
46.49

 
 
37.74

 
42.43

 
80.50

Effects of derivative settlements
2.02

 
 
10.49

 
19.18

 
3.23

Natural Gas:
 
 
 
 
 
 
 
 
Average NYMEX price (per MMBtu)
$
3.18

 
 
$
2.37

 
$
2.63

 
$
4.26

Average realized price, before the effects of derivative settlements (per Mcf)
3.10

 
 
2.27

 
2.60

 
4.58

Effects of derivative settlements (per Mcf)

 
 

 
0.43

 

NGLs (per Bbl):
 
 
 
 
 
 
 
 
Average realized price
$
20.36

 
 
$
12.98

 
$
14.66

 
$
30.64

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.

47

Table of Contents

Operating Costs and Expenses
Costs associated with producing oil, natural gas and NGLs are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells we own. As of December 31, 2016 (Successor) and December 31, 2015 (Predecessor) , CRP owned interests in 208 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 makes 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 trends 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 to development operations, audit and other fees for professional services and legal compliance.
Interest Expense. We finance a portion of our working capital requirements and capital expenditures with borrowings under our revolving credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under our revolving credit facility in interest expense.
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

48

Table of Contents

or losses, as well as cash receipts or payments on settled derivative contracts, are recognized in our consolidated and combined statements of operations. Cash flows from derivatives are reported as cash flows from operating activities.
A discussion of changes in operating costs and expenses is included in Results of Operations, below.
Results of Operations
For the Periods From October 11, 2016, Through December 31, 2016 (Successor) and January 1, 2016, Through October 10, 2016 (Predecessor) Compared to Year Ended December 31, 2015 (Predecessor)
Oil, Natural Gas and NGL Sales Revenues . The following table provides the components of our revenues for the periods indicated, as well as each period’s respective average prices and production volumes:
 
Successor
 
 
Predecessor
 
Combined
 
Predecessor
 
 
 
 
 
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
 
Year Ended December 31, 2016
 
Year Ended December 31, 2015
 
Increase/(Decrease)
 
 
 
 
 
$
 
%
Revenues (in thousands):
 
 
 
 
 
 
 
 
 
 
 
 
Oil sales
$
24,313

 
 
$
59,787

 
$
84,100

 
$
77,643

 
$
6,457

 
8
 %
Natural gas sales
3,449

 
 
6,045

 
9,494

 
7,965

 
1,529

 
19
 %
NGL sales
1,955

 
 
3,284

 
5,239

 
4,852

 
387

 
8
 %
Total Revenues
$
29,717

 
 
$
69,116

 
$
98,833

 
$
90,460

 
$
8,373

 
9
 %
Average sales price (1):
 
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
46.49

 
 
$
37.74

 
$
39.91

 
$
42.43

 
$
(2.52
)
 
(6
)%
Natural gas (per Mcf)
3.10

 
 
2.27

 
2.52

 
2.60

 
(0.08
)
 
(3
)%
NGL (per Bbl)
20.36

 
 
12.98

 
15.01

 
14.66

 
0.35

 
2
 %
Total (per Boe)
$
36.92

 
 
$
30.31

 
$
32.04

 
$
33.87

 
$
(1.83
)
 
(5
)%
Production:
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
523

 
 
1,584

 
2,107

 
1,830

 
277

 
15
 %
Natural gas (MMcf)
1,113

 
 
2,660

 
3,773

 
3,058

 
715

 
23
 %
NGLs (MBbls)
96

 
 
253

 
349

 
331

 
18

 
5
 %
Total (MBoe)(2)
805

 
 
2,280

 
3,085

 
2,671

 
414

 
15
 %
Average daily production volume:
 
 
 
 
 
 
 
 
 
 
 
 
Oil (Bbls/d)
6,378

 
 
5,577

 
5,757

 
5,014

 
743

 
15
 %
Natural gas (Mcf/d)
13,573

 
 
9,366

 
10,309

 
8,378

 
1,931

 
23
 %
NGLs (Bbls/d)
1,171

 
 
891

 
954

 
907

 
47

 
5
 %
Total (Boe/d)(2)
9,811

 
 
8,029

 
8,429

 
7,317

 
1,112

 
15
 %
 
(1)
Average prices shown in the table reflect prices before the effects of our realized commodity derivative transactions.
(2)
Total may not sum or recalculate due to rounding.
As reflected in the table above, our combined revenues for 2016 were 9% , or $8.4 million , higher than total revenues for 2015 . The increase was primarily due to a 15% increase in production sold in 2016 , which was partially offset by a 5% decrease in average sales price per Boe, compared to the prior year.
Combined oil sales increased 8% , or $6.5 million , for 2016 compared to the prior year period primarily due to a 15% increase in oil volumes sold, partially offset by an 6% decrease in the average sales price for oil. Combined natural gas sales increased 19% , or $1.5 million , for 2016 compared to the prior year period primarily due to a 23% increase in natural gas volumes sold, partially offset by a 3% decrease in the average sales price for natural gas. Combined NGL sales increased 8% , or $0.4 million , for 2016 compared to the prior year period primarily due to a 5% increase in the NGL volumes sold.
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.

49

Table of Contents

The following table sets forth selected operating data for the periods indicated:
 
Successor
 
 
Predecessor
 
Combined
 
Predecessor
 
 
 
 
 
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
 
Year Ended December 31, 2016
 
Year Ended December 31, 2015
 
Increase/(Decrease)
 
 
 
 
 
$
 
%
Operating Expenses (in thousands):
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating expenses
$
3,541

 
 
$
11,036

 
$
14,577

 
$
21,173

 
$
(6,596
)
 
(31
)%
Severance and ad valorem taxes
1,636

 
 
3,696

 
5,332

 
5,021

 
311

 
6
 %
Transportation, processing, gathering and other operating expense
2,187

 
 
4,583

 
6,770

 
5,732

 
1,038

 
18
 %
Production costs per Boe:
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating expenses
$
4.40

 
 
$
4.84

 
$
4.73

 
$
7.93

 
$
(3.20
)
 
(40
)%
Severance and ad valorem taxes
2.03

 
 
1.62

 
1.73

 
1.88

 
(0.15
)
 
(8
)%
Transportation, processing, gathering and other operating expense
2.72

 
 
2.01

 
2.19

 
2.15

 
0.04

 
2
 %
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. Combined LOE decreased 31% , or $6.6 million , in 2016 compared to 2015 , due in part to service providers lowering costs in light of the weak commodity price environment. Additionally, the number of wells placed on production in 2016 decreased 29% compared to 2015 . Workover expense decreased $2.0 million and we converted several rental units to permanent pumping units decreasing the amounts of rental expense by approximately $1.6 million in 2016 compared to the prior year period. Lastly, we decreased the use of contract labor and expenses related to repairs and maintenance by $1.2 million and $1.9 million, respectively, in 2016 compared to 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. Combined severance and ad valorem taxes increased 6% , or $0.3 million , in 2016 compared to 2015 , primarily due to higher sales volumes, partially offset by lower realized commodity prices. Combined severance and ad valorem taxes as a percentage of our revenue were 5.4% for 2016 compared to 5.6% for the prior year period.
Transportation, Processing, Gathering and Other Operating Expenses. Combined transportation, processing, gathering and other operating expenses in 2016 increased 18% , or $1.0 million , compared to 2015 , primarily due to an increase in natural gas production of 23% year over year, partially offset by lower realized commodity prices
Depreciation, Depletion, Amortization and Accretion of Asset Retirement Obligations. The following table summarizes our DD&A for the periods indicated: 
 
Successor
 
 
Predecessor
 
October 11, 2016
through
December 31, 2016
 
 
January 1, 2016
through
October 10, 2016
 
Year Ended December 31, 2015
(in thousands)
 
 
 
Depreciation, depletion, amortization and accretion of asset retirement obligations
$
14,877

 
 
$
62,964

 
$
90,084

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