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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2017
or
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
(State of Incorporation)
47-5381253
(I.R.S. Employer Identification No.)
1001 Seventeenth Street, Suite 1800, Denver, Colorado 80202
(Address of principal executive offices including zip code)
(Registrant’s telephone number, including area code): (720) 499-1400
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Class A Common Stock, par value $0.0001 per share
Name of each exchange on which registered
The NASDAQ Capital Market LLC
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
No
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
No
Securities registered pursuant to Section 12(g) of the Act: None
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
No
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
No
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.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging
growth company. (See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of
the Exchange Act).
Large accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Accelerated filer
Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or
revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
No
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant as of June 30, 2017, the last business day of the
registrant’s most recently completed second fiscal quarter, was approximately $2,479,264,380 based on the closing price of the shares of common stock on that
date.
As of February 20, 2018, there were 260,368,235 shares of Class A Common Stock, par value $0.0001 per share, and 15,661,338 shares of Class C Common
Stock, par value $0.0001 per share, outstanding.
TABLE OF CONTENTS
Glossary of Oil and Natural Gas Terms
Glossary of Certain Other Terms
Cautionary Statement Concerning Forward-Looking Statements
Business and Properties
Risk Factors
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosure
Part I
Part II
Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of
Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers and Corporate Governance
Executive Compensation
Part III
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
Part IV
Exhibits and Financial Statement Schedules
Form 10-K Summary
Items 1 and 2.
Item 1A.
Item 1B.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
Signatures
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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.
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. The process of preparing an oil and gas wellbore for production through the installation of permanent production
equipment, as well as perforation and fracture stimulation to optimize production.
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 location of oil or natural gas.
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.
Flush production. First yield from a flowing well during its most productive period after it is first completed and put on-line.
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.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of natural gas.
NGL. Natural gas liquids. These are naturally occurring substances found in natural gas, including ethane, butane, isobutane,
propane and natural gasoline, that can be collectively removed from produced natural gas, separated in these substances and sold.
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.
Proved developed reserves. Reserves that can be expected to be recovered through 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.
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.
3
Proved undeveloped reserves or PUD. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is required for completion or recompletion.
Realized price. The cash market price less differentials.
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.
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.
Royalty interest. An interest in an oil or gas property entitling the owner to shares of the production free of costs of exploration,
development and production operations.
Spot market price. The cash market price without reduction for expected quality, location, transportation and adjustments.
Wellbore. The hole drilled by a drill bit that is equipped for oil and natural gas production once the well has been completed. Also
called well or borehole.
Working interest. The interest in an oil and gas property (typically a leasehold interest) that gives the owner the right to drill,
produce and conduct operations on the property and to a share of production, subject to all royalties and other burdens and to all
costs of exploration, development and operations and all risks in connection therewith.
Workover. Operations on a producing well to restore or increase production.
WTI. West Texas Intermediate.
4
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. (i) Centennial Resource Development, Inc. and its consolidated subsidiaries including CRP,
following the closing of the Business Combination and (ii) 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 was 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 Riverstone 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.
GMT Acquisition. The acquisition of certain undeveloped acreage and producing oil and natural gas properties of GMT
Exploration Company LLC, which closed on June 8, 2017.
Initial Stockholders. Holders of our founder shares prior to our IPO, including Riverstone and our independent directors prior to
the Business Combination.
IPO. Silver Run Acquisition Corporation 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 Riverstone in a private placement
simultaneously with the closing of our IPO.
Public Warrants. Warrants for the purchase of shares of Class A Common Stock sold as part of the Units in our IPO, all of which
have been exercised or redeemed and are no longer outstanding.
Riverstone. Riverstone Investment Group LLC and its affiliates, including Silver Run Sponsor, LLC, a Delaware limited liability
company, 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, all outstanding shares of which were
converted into 26,100,000 shares of Class A Common Stock on May 25, 2017.
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.
5
Silverback. Silverback Exploration, LLC and Silverback Operating, LLC, collectively.
Silverback Acquisition. Our acquisition of leasehold interests and related upstream assets in Reeves County, Texas from
Silverback, 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
Class A Common Stock to certain other investors, which closed simultaneously with the consummation of the Silverback
Acquisition.
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.
Voting common stock. Our Class A Common Stock and Class C Common Stock.
6
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Throughout this Annual Report on 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
Annual Report on Form 10-K, 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 Annual Report
on 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 on Form 10-K.
Forward-looking statements may include statements about:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
our business strategy and future drilling plans;
our reserves and our ability to replace the reserves we produce through drilling and property acquisitions;
our drilling prospects, inventories, projects and programs;
our financial strategy, liquidity and capital required for our development program;
our realized oil, natural gas and NGL prices;
the timing and amount of our future production of oil, natural gas and NGLs;
our hedging strategy and results;
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;
general economic conditions;
credit markets;
uncertainty regarding our future operating results; and
our plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K 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 Annual Report on 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.
All forward-looking statements, expressed or implied, included in this Annual Report on 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.
7
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 Annual Report on
Form 10-K.
8
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
Overview
PART I
Centennial Resource Development, Inc. (the “Company,” “Centennial,” “we,” “us,” or “our”) is 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, and our properties consist of
large, contiguous acreage blocks primarily in Reeves County in West Texas and Lea County in New Mexico.
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 with an increased focus on optimizing completions, improving drilling results and drilling extended laterals. We also
intend to grow production and reserves through selective acquisitions that meet our strategic and financial objectives.
Presentation of Financial and Operating Data
On October 11, 2016, the Company 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 Company currently owns an approximate 94% membership interest in CRP due to various equity
transactions. The financial statement presentation distinguishes CRP as an accounting “Predecessor” for periods prior to the
Business Combination. Centennial is the “Successor” for periods after the Business Combination, which includes consolidation of
CRP subsequent to the Business Combination. Except as the context otherwise requires, references in the following discussion to
the “Company,” “Centennial,” “we,” “us,” or “our” with respect to periods prior to the closing of the Business Combination are to
CRP and its operations before the Business Combination.
Organizational Structure
The following diagram illustrates the current ownership structure of the company:
(1) CRD, one of the Centennial Contributors, also owns one share of Series A Preferred Stock, par value $0.0001 per share (the “Series A
Preferred Stock”) that provides CRD with the right to nominate and elect one director to the Company’s board of directors. The Series A
Preferred Stock does not have any other voting rights or rights with respect to dividends except distributions in liquidation in the amount of
$0.0001 per share.
Description of Our Properties
As of December 31, 2017, we operated 181 producing horizontal wells. We have established commercial production on our
acreage from eight distinct zones: the Avalon Shale, 1st Bone Spring, 2nd Bone Spring, 3rd Bone Spring, Upper Wolfcamp A,
Lower Wolfcamp A, Wolfcamp B and Wolfcamp C. As a result, we are able to efficiently develop our drilling inventory and focus
9
on maximizing returns to our stakeholders. As of December 31, 2017, we had six operated rigs running on our acreage, five of
which are in Reeves County and one of which is in Lea County.
As of December 31, 2017, we have leased or acquired approximately 84,718 net acres, approximately 91% of which we
operate. In addition, we own 1,521 net mineral acres in the Delaware Basin. Approximately 85% of our total acreage as of
December 31, 2017 was located in Texas, primarily Reeves County, in the southern portion of the Delaware Basin and
approximately 15% is located in New Mexico, primarily in Lea County, in the northern portion of the Delaware Basin. As of
December 31, 2017, over 64% of our net acreage is held by production. The relatively high proportion of our operated acreage
that is held by production gives us significant operational control and capital spending flexibility. This allows us to execute our
development program with significant control over the timing and allocation of capital expenditures and application of the
optimal drilling and completion techniques to efficiently develop our resource base. 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
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. The pre-tax PV 10% amounts shown in the following table are 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 on Form 10-K.
The following table summarizes estimated proved reserves, pre-tax 10%, and standardized measure of discounted future cash
flows as of December 31, 2017 (Successor), December 31, 2016 (Successor), and December 31, 2015 (Predecessor):
Proved developed reserves:
Oil (MBbls)
Natural gas (MMcf)
NGL (MBbls)
Total proved developed reserves (MBoe)
Proved undeveloped reserves:
Oil (MBbls)
Natural gas (MMcf)
NGL (MBbls)
Total proved undeveloped reserves (MBoe)
Total proved reserves:
Oil (MBbls)
Natural gas (MMcf)
NGL (MBbls)
Total proved reserves (MBoe)
Proved developed reserves %
Proved undeveloped reserves %
Successor
December 31,
2017
December 31,
2016
Predecessor
December 31,
2015
41,786
126,065
12,133
74,929
59,147
201,147
18,853
111,525
100,933
327,212
30,986
186,454
14,551
42,190
3,618
25,200
31,914
106,154
8,152
57,759
46,466
148,344
11,770
82,959
9,347
12,711
1,603
13,068
13,852
19,731
2,248
19,389
23,199
32,442
3,851
32,457
40%
60%
30%
70%
40%
60%
Reserve values (in millions):
Standard measure of discounted future net cash flows
Discounted future income tax expense
Total proved pre-tax PV 10% (1)
$
$
1,503.3
244.8
1,748.1
$
$
375.1
52.4
427.5
$
$
135.1
10.4
145.5
10
(1)
Pre-tax PV 10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of
discounted future net cash flows (the ‘‘Standardized Measure’’), which is the most directly comparable GAAP financial measure. Pre-tax
PV 10% is computed on the same basis as the Standardized Measure but without deducting future income taxes. We believe pre-tax PV
10% is a useful measure for investors when evaluating the relative monetary significance of our oil and natural gas properties. We further
believe investors may utilize our pre-tax PV 10% as a basis for comparison of the relative size and value of our proved reserves to other
companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our
management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions.
However, pre-tax PV 10% is not a substitute for the Standardized Measure. Our pre-tax PV 10% and Standardized Measure do not purport
to present the fair value of our proved oil, NGL and natural gas reserves.
Proved Undeveloped Reserves. Significant changes to our proved undeveloped (“PUD”) reserves that occurred during 2017 are
summarized in the table below:
Proved undeveloped reserves at January 1,
Transferred to proved developed reserves
Revisions to previous estimates
Extensions and discoveries
Proved undeveloped reserves at December 31,
2017
(Mboe)
57,759
(18,141)
5,277
66,630
111,525
During 2017, we spent $168.5 million in capital expenditures to convert 18.1 MMBoe of PUD reserves to proved developed
reserves. Revisions of previous estimates of 5.3 MMBoe are composed of positive revisions of 15.1 MMBoe relating to
adjustments to PUD well locations scheduled to be drilled at longer lateral lengths and upward performance revisions partially
offset by 9.8 MMBoe of negative revisions associated with PUD reclassification to unproven reserves as they are no longer
expected to be developed within the five years of their initial recording in accordance with SEC rules. In addition, we added 66.6
MMBoe of PUD reserves from extensions and discoveries during the year primarily due to successful drilling from our 2017 six-
rig development drilling program, the majority of which were in the Upper Wolfcamp A zone. All of our PUD drilling locations
are scheduled to be drilled within five years of their initial booking. The Company’s PUD to proved developed reserves
conversion rate was 36% in 2017.
Preparation of Reserve Estimates
Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil, natural gas and NGLs, which, by
analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a
given date forward, from known reservoirs and under existing economic conditions, operating methods and government
regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic
methods are used, the Securities and Exchange Commission (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, 2017, 2016 and
2015 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, natural gas and NGLs 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 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.
Evaluation and Review of Proved Reserves. Our historical proved reserve estimates as of December 31, 2017, 2016 and 2015
were prepared based on reports by Netherland, Sewell & Associates, Inc. (“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
11
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 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. Jeff Thompson has served as our Vice
President of Reservoir Engineering since July 2017. Prior to that, Mr. Thompson served as General Manager at QEP Resources
leading the reservoir engineering, geoscience, and regulatory teams focused on the Williston Basin from 2016 to 2017. Mr.
Thompson also served as the General Manager of the Greater Green River Basin Team from 2015 to 2016 and worked as the
Reservoir Engineering Manager of QEP’s Williston Basin assets from 2012 to 2015. Mr. Thompson originally joined QEP
Resources (formerly Questar E&P) in 2005 as a member of the Mid-Continent asset team functioning in various engineering roles
before managing the Mid-Continent Reservoir Engineering Team in 2012. Mr. Thompson earned his B.S. in Petroleum
Engineering from the University of Oklahoma. He is a Registered Professional Engineer in Oklahoma and member of the Society
of Petroleum Engineers.
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:
Production data:
Oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Total (MBoe)
Average realized prices (excluding effect of hedges):
Oil (per Bbl)
Natural gas (per Mcf)
NGL (per Bbl)
Per BOE
Production costs per Boe:
Lease operating expenses
Severance and ad valorem taxes
Transportation, processing, gathering and other operating
expenses
Contract termination and rig stacking
Productive Wells
Successor
Predecessor
Year Ended
December 31,
2017
October 11, 2016
through
December 31,
January 1, 2016
through
October 10, 2016
Year Ended
December 31,
2015
6,994
17,754
1,678
11,630
48.17
$
$
$
2.75
26.28
36.96
3.55
1.99
2.95
—
$
$
$
523
1,113
96
805
46.49
3.10
20.36
36.92
4.40
2.03
2.72
—
$
$
$
1,584
2,660
253
2,280
37.74
$
$
$
2.27
12.98
30.31
4.84
1.62
2.01
—
1,830
3,058
331
2,671
42.43
2.60
14.66
33.87
7.93
1.88
2.15
0.89
As of December 31, 2017, we owned an approximate 64% average working interest in 315 gross (203 net) productive wells.
Our wells are primarily oil wells (299 gross/188 net productive 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.
12
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, 2017 relating to our gross and net developed and undeveloped
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(3)
Gross(1)
Net(2)
Gross(1)
Net(2)
Gross(1)
Net(2)
22,880
21,407
104,564
63,311
127,444
84,718
(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.
(3) Does not include our 1,521 net mineral acres.
The following table sets forth the gross and net undeveloped acreage, as of December 31, 2017, that will expire over the next
five years unless production is established within the spacing units covering the acreage, the lease is renewed or extended under
continuous drilling provisions prior to the primary term expiration dates, or pursuant to other terms of the lease agreements.
2018
2019
2020
2021
2022
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross
Net
17,898
10,724
23,902
14,270
11,910
1,752
480
480
236
189
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.
Development Wells:
Productive(1)
Dry
Exploratory Wells:
Productive(1)
Dry
Total
Successor
Predecessor
Year ended
December 31, 2017
October 11, 2016
through
December 31, 2016
January 1, 2016
through
October 10, 2016
Year Ended
December 31, 2015
Gross
Net
Gross
Net
Gross
Net
Gross
Net
69
1
70
1
1
2
72
65.2
1.0
66.2
1.0
1.0
2.0
68.2
5
—
5
—
—
—
5
2.5
—
2.5
—
—
—
2.5
10
—
10
—
—
—
10
7.0
—
7.0
—
—
—
7.0
16
—
16
—
—
—
16
12.4
—
12.4
—
—
—
12.4
(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.
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Title to Properties
We believe that we have satisfactory title to substantially all of our producing properties in accordance with generally
accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, working and
other outstanding interests customary in the industry. In most cases, we investigate title and obtain title opinions from counsel
only when we acquire producing properties or before commencement of drilling operations.
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 NGLs under contracts with terms of greater than twelve months and the majority of our natural gas and all of our oil
under contracts with terms of less than twelve months.
We normally sell production to a relatively small number of customers, as is customary in our business. The tables below
present percentages by purchaser that accounted for 10% or more of our total oil, NGL, and natural gas sales for the years ended
December 31, 2017, 2016, and 2015.
Year Ended December 31, 2017
Shell Trading (US) Company
BP America
Eagleclaw Midstream Ventures, LLC
Year Ended December 31, 2016
Plains Marketing, LP
Shell Trading (US) Company
Permian Transport and Trading
Year Ended December 31, 2015
Plains Marketing, LP
33%
16%
14%
48%
22%
11%
64%
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 a highly competitive environment, and we compete with both major integrated and other
independent oil and natural gas companies in all aspects of our business to explore, develop and operate our properties and market
our production. Competitive conditions may be affected by future legislation and regulations as the United States develops new
energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to
factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions,
weather conditions, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic
conditions. We also face indirect competition from alternative energy sources, including wind, solar and electric power. 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.
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.
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Regulation of the Oil and Natural Gas Industry
Our operations are subject to extensive federal, state and local laws and regulations. All of the jurisdictions in which we own
or operate producing properties have statutory provisions regulating the development and production of oil and natural gas,
including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of
wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing
and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject
to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration
units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well
as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability
or fair apportionment of production from fields and individual wells.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the
industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with
all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable
to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas
industry are regularly considered by Congress, the states, Federal Energy Regulatory Commission (“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, natural gas and NGLs 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 New Mexico and Texas, which regulate 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 New Mexico and
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, natural
gas and NGLs 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, New Mexico
and Texas impose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within their
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.
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, 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.
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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 Natural Gas Policy Act of
1978 (“NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting
wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate
commerce is regulated primarily under the Natural Gas Act of 1938 (“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 federal Energy Policy Act of 2005 (“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. In January 2018, FERC increased 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 $1,238,271 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 Commodity Futures
Trading Commission (“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.
Natural gas gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states.
Section 1(b) of the NGA exempts companies that provide natural gas gathering services from regulation by FERC as a “natural
gas company” under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-
jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of
facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional
transmission facilities as non-jurisdictional gathering facilities, or vice versa, and depending on the scope of that decision, our
costs of getting gas to point-of-sale locations may increase. We believe that the natural gas pipelines in our gathering systems
meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas
company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is
the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on
future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes
various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such
regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory
scrutiny in the future.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate
regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline
rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate
natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural
gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any
16
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, 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 operations are subject to stringent federal, state and local laws and regulations governing the occupational safety and
health aspects of our operations, the discharge of materials into the environment, and protection of the environment and natural
resources (including threatened and endangered species and their habitats). Numerous governmental entities, including 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, often requiring difficult and costly actions. These laws and regulations may,
among other things, (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types,
quantities and concentrations of various substances that can be released into the environment or injected into formations in
connection with drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands, and other protected areas; (iv) require remedial measures to prevent or mitigate pollution from former and ongoing
operations, such as requirements to close pits and plug abandoned wells; (v) apply specific health and safety criteria addressing
worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any
failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the
imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects,
and the issuance of orders enjoining performance of some or all of our operations.
The following is a summary of the more significant existing and proposed environmental and occupational safety and health
laws, as amended from time to time, to which our business operations are or may be subject, and for which compliance may have
a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous Substances and Handling Wastes
The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws, regulate the generation, transportation,
treatment, storage, disposal and cleanup of hazardous and nonhazardous solid wastes. Pursuant to rules issued by the EPA, the
individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent
requirements. Drilling fluids, produced waters and other wastes associated with the exploration, development and production of
oil, natural gas and NGLs, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and,
instead, are regulated under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws.
However, it is possible that certain oil and natural gas drilling and production wastes now classified as nonhazardous solid wastes
could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered
into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain
exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent
decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations
pertaining to oil and natural gas wastes, or to sign a determination that revision of the regulations is not necessary. Were the EPA
to propose a rulemaking, the consent decree requires that the EPA take final action by no later than July 15, 2021. Any such
change could result in an increase in our, as well as the oil, natural gas and NGL exploration and production industry’s, costs to
manage and dispose of 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.
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund
law, and comparable state laws impose joint and several liability, without regard to fault or the legality of conduct, on classes of
persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include
the current and former owners or operators of the site where the release occurred and anyone who disposed or arranged for the
disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability
for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural
resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act
in response to threats to the public health or the environment, and to seek to recover from the responsible classes of persons the
costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal
17
injury and property damage allegedly caused by the hazardous substances released into the environment. generate materials in the
course of our operations that may be regulated as hazardous substances.
We currently own, lease or operate numerous properties that have been used for oil, natural gas and NGL exploration,
production and processing 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 treatment or disposal. In addition, some of our properties have been operated by third parties or by
previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not
under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA,
RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which
could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of
remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.
Water Discharges
The Clean Water Act (“CWA”) and comparable state laws impose restrictions and strict controls with respect to the discharge
of pollutants, including spills and leaks of hazardous substances, into state waters and waters of the United States. The discharge
of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an
analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require
appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a
petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or
coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory
agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other CWA
requirements and analogous state laws and regulations.
The CWA also prohibits the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized
by permit. The EPA and the U.S. Army Corps of Engineers issued final rules attempting to clarify the federal jurisdictional reach
over waters of the United States (the “WOTUS”), but this rule has been stayed nationwide by the U.S. Court of Appeals for the
Sixth Circuit while the appellate court and numerous federal district courts ponder lawsuits opposing implementation of the rule.
The U.S. Supreme Court considered the issue of which court has jurisdiction to hear challenges to the WOTUS rule, and in
January 2018 concluded that jurisdiction rests with the federal district courts. In addition, in 2017, President Trump issued an
executive order directing the EPA and the U.S. Army Corps of Engineers to review the WOTUS rule and, if the agencies’ reviews
find that the rule does not meet the executive order’s goal of promoting economic growth while reducing regulatory uncertainty,
to initiate a new rulemaking to repeal or revise the rule. Pursuant to the executive order, in June 2017, the EPA and U.S. Army
Corps of Engineers formally proposed to rescind the WOTUS rule. In January 2018, the EPA and the U.S. Army Corps of
Engineers finalized a rule that would delay applicability of the WOTUS rule for two years. Repeal of or revisions to the WOTUS
rule will require the EPA and the U.S. Army Corps of Engineers to initiate a rulemaking that is subject to public notice and
comment, as well as judicial challenges. Substantial uncertainty exists with respect to future implementation of the WOTUS rule.
The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (the “OPA”), which amends
and augments the oil spill provisions of the CWA 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.
Subsurface Injections
In the course of our operations, we produce water in addition to natural gas, crude oil and NGLs. Water that is not recycled
may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground
injection operations are regulated pursuant to the Underground Injection Control (the “UIC”) program established under the
federal Safe Drinking Water Act (the “SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an
analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well
operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the
inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately
increase the cost of our operations. For example, in response to recent seismic events near below-ground disposal wells used for
the injection of natural gas- and oil-related wastewaters, federal and some state agencies have begun investigating whether such
wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such disposal
18
wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, additional
requirements related to seismic safety. These seismic events have also led to an increase in tort lawsuits filed against exploration
and production companies, as well as the owners of underground injection wells. Increased costs associated with the
transportation and disposal of produced water, including the cost of complying with regulations concerning produced water
disposal, may reduce our profitability; however, these costs are commonly incurred by all oil, natural gas and NGL producers, and
we do not believe that the costs associated with the disposal of produced water will have a material adverse effect on our
operations.
Air Emissions
The federal Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such
as tank batteries, through air emissions standards, construction and operating permitting programs and the imposition of other
compliance standards. These laws and regulations may require us to obtain pre-approval for the construction or modification of
certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent
air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain
permits has the potential to delay the development of our projects. Recently, there has been increased regulation with respect to air
emissions result from the oil and natural gas sector. For example, the EPA promulgated rules in 2012 under the CAA that subject
oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance
Standards (“NSPS”), and a separate set of requirements to address certain hazardous air pollutants frequently associated with oil
and natural gas production and processing activities pursuant to the National Emissions Standards for Hazardous Air Pollutants
(“NESHAP”) program.
In June 2016, the EPA published final rules establishing new air emission controls for methane emissions from certain new,
modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing,
transmission and storage activities. The EPA’s final rules include NSPS to limit methane emissions from equipment and processes
across the oil and natural gas source category. The rules also extend limitations on volatile organic compound (“VOC”) emissions
to sources that were unregulated under the previous NSPS at Subpart OOOO. Affected methane and VOC sources include
hydraulically fractured (or re-fractured) oil and natural gas well completions, fugitive emissions from well sites and compressors,
and pneumatic pumps. Several states and industry groups have filed suit before the U.S. Court of Appeals for the D.C. Circuit (the
“D.C. Circuit”) challenging the EPA’s implementation of the methane rule and the EPA’s legal authority to issue the methane
rules. However, in April 2017, the EPA announced that it will review its methane rule for new, modified and reconstructed sources
and to initiate reconsideration proceedings to potentially revise or rescind portions of the rule. In addition, the EPA issued a stay
of the June 3, 2017 compliance date applicable to fugitive emissions monitoring requirements for 90 days. In July 2017, the D.C.
Circuit found that the EPA decision to issue the stay was not permissible under the CAA and vacated the stay, but subsequently
issued a revised opinion allowing the agency to stay implementation of the rule for two weeks. However, in June 2017 the EPA
issued a proposed rulemaking to stay the requirements of Subpart OOOOa for a period of two years and to revisit implementation
of Subpart OOOOa in its entirety. The EPA has not yet published a final rule, but, as a result of these developments, future
implementation of the 2016 standards is uncertain at this time.
The Bureau of Land Management (the “BLM”) also finalized rules in November 2016 that seek to limit methane emissions
from exploration and production activities on federal lands by imposing limitations on venting and flaring of natural gas, as well
as requirements for the implementation of leak detection and repair programs for certain processes and equipment. However,
President Trump issued an executive order directing the BLM to review and potentially repeal or revise the rule. In June 2017 and
October 2017, the BLM announced its intention to delay compliance with the requirements of the BLM methane rule until the
agency can issue a revised rule. Also in October 2017, a federal magistrate judge found that the BLM did not have the authority to
cease enforcing the rule. In December 2017, the BLM petitioned the U.S. Court of Appeals for the Ninth Circuit to review and
overturn the magistrate judge’s decision. Also in December 2017, the BLM issued a final rule postponing compliance dates for
portions of the rule until January 17, 2019. As a result of these developments, substantial uncertainty exists with respect to its
implementation.
The EPA also finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a
single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small
facilities (such as tank batteries), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air
permitting requirements, which in turn could result in operational delays or require us to install costly pollution control
equipment. In addition, in October 2015, the EPA issued a final rule under the CAA lowering the National Ambient Air Quality
Standards (“NAAQS”) for ground-level ozone from the current standard of 75 parts per billion (“ppb”) for the current 8-hour
primary and secondary ozone standards to 70 ppb for both standards. The final rule became effective on December 28, 2015. The
EPA issued its anticipated area designations in November 2017 and December 2017. States are expected to implement more
stringent permitting and pollution control requirements as a result of this new final rule, which could apply to our operations.
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Compliance with one or more of these and other air pollution control and permitting requirements has the potential to delay
the development of natural gas, oil and NGL projects and increase our costs of development and production, which costs could be
significant.
Regulation of GHG Emissions
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) endanger public
health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things,
establish Prevention of Significant Deterioration (“PSD”) preconstruction and Title V operating permit reviews for certain large
stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required
to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards that
will typically be established by state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual
reporting of GHG emissions from large GHG emission sources in the United States, including certain onshore and offshore
natural gas, oil and NGL production sources, which include certain of our operations. As discussed above, federal regulatory
action regarding GHG emissions from the oil and gas sector has focused on methane emissions; however, federal implementation
of the finalized 2016 methane rule is uncertain at this time (as also discussed above).
While Congress has, from time to time, considered legislation to reduce emissions of GHGs, no significant legislation has
been adopted at the federal level. In the absence of such federal climate legislation, a number of state and regional cap-and-trade
programs have emerged that typically require major sources of GHG emissions to acquire and surrender emission allowances in
return for emitting those GHGs. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the
Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG
emissions targets and be transparent about the measures each country will take to achieve its GHG emissions targets. The Paris
Agreement entered into force on November 4, 2016 upon achieving its threshold for ratification by signatory countries. A long-
term goal of the Paris Agreement is to limit global warming to below two degrees Celsius by 2100 from temperatures in the pre-
industrial era. However, the Paris Agreement does not impose any binding obligations on its participants. In June 2017, President
Trump stated that the United States intends to withdraw from the Paris Agreement, but may enter into a future international
agreement related to GHGs. In August 2017, the U.S. State Department officially informed the United Nations of its intent to
withdraw from the Paris Agreement unless it is renegotiated. The Paris Agreement provides for a four-year exit process beginning
when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States
adherence to the exit process is uncertain and the terms on which the United States may reenter the Paris Agreement or a
separately negotiated agreement are unclear at this time.
Although it is not possible at this time to predict how new laws or regulations that may be adopted or issued to address GHG
emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting
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, as well as delay or restrict our ability to permit GHG emissions from new or
modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the natural gas, oil and
NGLs we produce and lower the value of our reserves. Finally, it should be noted 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, droughts and other extreme climatic events; if any such effects were to occur, they could have an adverse effect
on our exploration and production operations.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, natural gas and NGLs
from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is
typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority
over certain aspects of the process. For example, the EPA published final CAA regulations in 2012 and, more recently, in June
2016, establishing performance standards, including standards for the capture of air emissions released during oil and natural gas
hydraulic fracturing, leak detection, and permitting; published in June 2016 an effluent limitation guideline final rule prohibiting
the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater
treatment plants; and issued in 2014 a prepublication version of its Advance Notice of Proposed Rulemaking regarding Toxic
Substances Control Act (“TSCA”) reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in March
2015, the BLM adopted rules establishing stringent standards relating to hydraulic fracturing on federal and American Indian
lands. In June 2016, a federal district court judge in Wyoming struck down this final rule, finding that the BLM lacked authority
to promulgate the rule. That ruling was appealed, but in September 2017 the U.S. Court of Appeals for the Tenth Circuit dismissed
the appeal and remanded with directions to vacate the lower court’s opinion, leaving the final rule in place. However, following
the issuance of an executive order by President Trump to review rules related to the energy industry, the BLM initiated a
rulemaking to rescind the final rule in December 2017. Also, in December 2016, the EPA released its final report on the potential
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impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated
with hydraulic fracturing may impact drinking water resources “under certain limited circumstances.”
From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic
fracturing and to require disclosure of the chemicals used in the fracturing process. Meanwhile, the regulation of hydraulic
fracturing has continued at the state level. For example, Wyoming has promulgated rules related to the public disclosure of
substances used in hydraulic fluid, testing requirements for water wells near drilling sites and leak detection and repair
requirements for fugitive emissions from oil and gas production facilities.
In the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where
we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also
could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of
exploration, development, or production activities.
Activities on Federal Lands
Oil and natural gas exploration, development and production activities on federal lands, including American Indian lands and
lands administered by the BLM, are frequently subject to permitting delays. Operations on these lands are also subject to the
National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the BLM, to evaluate major actions
having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an
Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if
necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and
comment. We currently have exploration, development and production activities on federal lands. Our proposed exploration,
development and production activities are expected to include leasing of federal mineral interests, which will require the
acquisition of governmental permits or authorizations that are subject to the requirements of NEPA. This process has the potential
to delay or limit, or increase the cost of, the development of natural gas, oil and NGL projects. Authorizations under NEPA are
also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation
strategies recommended in the Environmental Assessments or Environmental Impact Statements, we could incur added costs,
which may be substantial.
ESA and Migratory Birds
The federal Endangered Species Act (“ESA”) and 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 that potentially could be listed as threatened or endangered under the ESA
may exist. Moreover, as a result of a 2011 settlement agreement, the U.S. Fish and Wildlife Service (“FWS”) was required to
make a determination on listing of numerous species as endangered or threatened under the ESA by no later than completion of
the agency’s 2017 fiscal year. The FWS did not meet that deadline. If we were to have a portion of our leases designated as
critical or suitable habitat, it could adversely impact the value of our leases. In addition, the federal government recently has
issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after migratory birds were found
dead 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, time delays or limitations on our exploration and production activities, which 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.
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 activities and to maintain these permits and compliance with
their requirements for ongoing 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.
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Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of
our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this
insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its
purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially
adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.
Employees
As of December 31, 2017, we had 119 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 1001 Seventeenth Street, Suite 1800, Denver, Colorado 80202, and our
telephone number is (720) 499-1400. We also have office space in Jal, New Mexico, 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 Annual
Report on Form 10-K 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.
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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.
Risks Related to the Oil and Natural Gas Industry and Our Business
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, 2017, 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:
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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
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 2015, our realized oil price for 2016 fell 6% to $39.91 per barrel and increased in
2017 to $48.17 per barrel. Similarly, our realized natural gas price for 2016 dropped 3% to $2.52 per Mcf and increased to $2.75
per Mcf in 2017, and our realized price for NGLs increased 2% to $15.01 per barrel and to $26.28 per barrel in 2017. 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
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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:
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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:
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landing a wellbore in the desired drilling zone;
staying in the desired drilling zone while drilling horizontally through the formation;
running our casing the entire length of the wellbore; and
being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that we face while completing wells include the following:
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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.
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Furthermore, the results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas
that are more developed and have a longer history of established production. Newer or emerging formations and areas have
limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our
drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as
anticipated, and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could
decline in the future.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our
business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our development, acquisition and
production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in
commercially viable oil and natural gas production.
Our decisions to develop or purchase prospects or properties will depend in part on the evaluation of data obtained through
geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or
subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates
depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying
assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing
and operating wells is often uncertain.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
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delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from
wastewater disposal, emission of 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.
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 from time to time. As of
December 31, 2017, we had entered into basis swaps through December 2018 covering a total of 2,730 MBbls of our projected oil
production at a weighted average differential of $0.06 per bbl. In addition, as of December 31, 2017, we had entered into basis
swaps covering a total of 1.8 million MMBtu of our projected natural gas production through December 2018 and 1.8 million
MMBtu through December 2019, both at a weighted average differential of $0.43 per MMBtu. Accordingly, our earnings may
fluctuate significantly as a result of changes in fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
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production is less than the volume covered by the derivative instruments;
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
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there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into
derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our
cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital
expenditures and make payments on our indebtedness, and which could also limit the size of CRP’s borrowing base. Future
collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest
rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural
gas, which could also have a material adverse effect on our financial condition.
Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract.
Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the
counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We
are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we accurately predict
sudden changes, our ability to negate the risk may be limited depending upon market conditions.
During periods of declining commodity prices, our derivative contract receivable positions generally increase, which
increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their
nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve
estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and
many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any
significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value
of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures.
We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of
this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and
quantities of recoverable oil and natural gas reserves may vary from our estimates. For instance, initial production rates reported
by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse
than expected, and production declines may be greater than our estimates and may be more rapid and irregular when compared to
initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of
development activities, current commodity prices and other existing factors. Any significant variance could materially affect the
estimated quantities and present value of our reserves.
You should not assume that the present value of future net revenues from our reserves is the current market value of our
estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date
of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example,
our estimated proved reserves as of December 31, 2017, and related standardized measure were calculated under rules of the SEC
using twelve-month trailing average benchmark prices of $47.79 per barrel of oil (WTI Posted) and $2.98 per MMBtu (Henry
Hub spot), which may be substantially higher or lower than the available spot prices in 2018. 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, 2017, we have leased or acquired approximately 84,718 net acres, approximately 91% of which we
operate. As of December 31, 2017, we operated 181 producing horizontal wells. We will have limited ability to exercise influence
over the operations of the drilling locations operated by our partners, and there is the risk that our partners may at any time have
economic, business or legal interests or goals that are inconsistent with ours. Furthermore, the success and timing of development
activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:
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the timing and amount of capital expenditures;
the operator’s expertise and financial resources;
the approval of other participants in drilling wells;
the selection of technology; and
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the rate of production of reserves, if any.
This limited ability to exercise control over the operations and associated costs of some of our drilling locations could
prevent the realization of targeted returns on capital in drilling or acquisition activities.
Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could
materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the amount of capital that
would be necessary to drill such locations.
We have specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling
activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill
and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of
capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering
system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory
approvals and other factors. Because of these uncertain factors, we do not know if the numerous identified drilling locations will
ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless
production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are
obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently
identified.
As 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, 2017, over 64% of our total net acreage 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 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,
primarily in West Texas. At December 31, 2017, all of our total estimated proved reserves were attributable to properties located
in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand
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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, 2017, 60% of our total estimated proved reserves were classified as proved undeveloped. Development
of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently
anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in
commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result
in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify
our PUDs as unproved reserves. Further, we may be required to write-down our PUDs if we do not drill those wells within five
years after their respective dates of booking.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their
carrying value, we may be required to take write-downs of the carrying values of our properties.
Accounting rules that we periodically review the carrying value of our properties for possible impairment. Based on
prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and
the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down
the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. Recently, commodity prices have
declined significantly. Lower commodity prices in the future could result in impairments of our properties, which could have a
material adverse effect on our results of operations for the periods in which such charges are taken.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which
would adversely affect our future cash flows and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon
reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or
continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our
future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success
in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not
be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to
replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results
of operations would be materially and adversely affected.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural
gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The
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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, 2017, sales to Shell Trading (US) Company (“Shell”), BP America and Eagleclaw Midstream Ventures, LLC
accounted for 33%, 16% and 14%, respectively, of total revenue. For the year ended December 31, 2016, sales to Plains
Marketing, LP (“Plains”), Shell and Permian Transport and Trading accounted for 48%, 22%, and 11%, respectively, of total
revenue. For the year ended December 31, 2015, we only had one major customer, Plains, which accounted for 64% 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
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 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.
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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:
•
•
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.
•
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•
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of
claims for:
•
•
•
•
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injury or loss of life;
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:
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•
•
•
•
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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
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disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and
purchase prices higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify
additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or
successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets
into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse
effect on our financial condition and results of operations. In addition, debt agreements impose certain limitations on our ability to
enter into mergers or combination transactions and 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, 2017 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 activity has 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, has increased, as have the costs for
those items. To the extent that commodity prices continue to 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. Such costs may rise faster than increases in our revenue as 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 EP Act of 2005, FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current
violations of up to $1,238,271 million per day for each violation and disgorgement of profits associated with any violation. While
our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that
may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We
also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those
and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the
future could subject us to civil penalty liability.
Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced
demand for the oil and natural gas that we produce, while potential physical effects of climate change could disrupt our
production and cause us to incur significant costs in preparing for or responding to those effects.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health
and the environment, the EPA has adopted regulations pursuant to the CAA that, among other things, require PSD preconstruction
and Title V operating permits for certain large stationary sources. Facilities required to obtain PSD permits for their GHG
emissions are also required to meet “best available control technology” standards that are being established by the states or, in
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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, which include certain of our operations. Furthermore, in June 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. However, the EPA has recently indicated that it intends to reconsider certain aspects of this rule, and in June 2017
issued a proposed rulemaking that would stay the requirements of the methane rule for a period of two years. 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 became 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. In June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement
and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework. In August 2017,
the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris
Agreement unless it is renegotiated. 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 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 CAA establishing performance standards, including standards for
the capture of air emissions released during hydraulic fracturing (although the Trump Administration has indicated an intent to
review this rule), 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
BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal
and American Indian lands (which was challenged in a U.S. federal trial court, resulting in a decision in June 2016 against the
rule, an appeal of that decision, and a U.S. federal appeals court ruling in September 2017 dismissing the appeals and vacating the
trial court decision); the rule is currently the subject of a December 2017 final rulemaking by the BLM to rescind it. 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.
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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
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resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified
personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past three years due to
competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring
prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising
additional capital, which could have a material adverse effect on our business.
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain,
any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical
personnel could have a material adverse effect on our business, financial condition and results of operations.
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,
2017, we had no borrowings outstanding under its credit facility. Interest is calculated under the terms of CRP’s credit agreement
based on a LIBOR spread. Recent and continuing disruptions and volatility in the global financial markets may lead to a
contraction in credit availability impacting our ability to finance operations. We require continued access to capital. A significant
reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our
planned growth and operating results.
We may be subject to risks in connection with acquisitions of properties.
The successful acquisition of producing properties requires an assessment of several factors, including:
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recoverable reserves;
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.
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.
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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 CFTC and the SEC to
promulgate rules and regulations implementing the Dodd-Frank Act. In October 2011, the CFTC issued regulations to set position
limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The
initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012.
However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and
equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging
transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet
proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. In addition,
certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for
uncleared swaps. Although we expect to qualify for the end-user exception from such margin requirements for swaps entered into
to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may
change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-
user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore
reducing our ability to execute hedges to reduce risk and protect cash flow.
The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the
regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations
could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the
availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing
derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of
operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan
for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas
prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural
gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is
to lower commodity prices. Any of these consequences could have a material and adverse effect on us and our financial condition.
In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives
market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the
impact of which is not clear at this time.
The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of our estimated oil
and natural gas reserves.
Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies
subject to the rules and regulations of the SEC. Standardized measure requires the use of specific pricing as required by the SEC
as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices
ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it
reflect the actual costs that will be required to produce or develop the oil and natural gas properties. As a result, estimates
included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received, and
the standardized measure of our estimated reserves included in this Annual Report on Form 10-K 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.
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A security interruption or failure with respect to our information technology systems could harm our ability to effectively
operate our business.
Our ability to effectively manage and operate our business depends significantly on information technology systems. The
failure of these systems to operate effectively and support our operations, challenges in transitioning to upgraded or replacement
systems, difficulty in integrating new or updated systems, or a breach in security of these systems could adversely impact the
operations of our business.
Any breach of our network may result in the loss of valuable business data, misappropriation of our customers’ or employees’
personal information, or a disruption of our business, which could harm our customer relationships and reputation, and result in
lost revenues, fines or lawsuits.
Moreover, we must comply with increasingly complex and rigorous regulatory standards enacted to protect business and
personal data. Any failure to comply with these regulatory standards could subject us to legal and reputational risks. Misuse of or
failure to secure personal information could also result in violation of data privacy laws and regulations, proceedings against us
by governmental entities or others, damage to our reputation and credibility, and could have a negative impact on revenues and
profits.
Changes in laws or regulations, or a failure to comply with any laws and regulations, may adversely affect our business,
investments and results of operations.
We are subject to laws, regulations and rules enacted by national, regional and local governments and NASDAQ. In
particular, we are required to comply with certain SEC, NASDAQ and other legal or regulatory requirements. Compliance with,
and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Those laws, regulations and
rules and their interpretation and application may also change from time to time and those changes could have a material adverse
effect on our business, investments and results of operations. In addition, a failure to comply with applicable laws, regulations and
rules, as interpreted and applied, could have a material adverse effect on our business and results of operations.
Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax
returns could adversely affect our financial condition and results of operations.
We are subject to income taxes in the United States, and our domestic tax liabilities are subject to the allocation of expenses
in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors,
including:
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changes in the valuation of our deferred tax assets and liabilities;
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.
The recently passed comprehensive tax reform bill could adversely affect our business and financial condition.
On December 22, 2017, President Trump signed into law H.R. 1 (commonly referred to as the “Jobs Act”), a comprehensive
tax reform bill that significantly reforms the Internal Revenue Code of 1986, as amended. The Jobs Act, among other things,
contains significant changes to corporate taxation, including a permanent reduction of the corporate income tax rate, a partial
limitation on the deductibility of business interest expense, limitation of the deduction for certain net operating losses to 80% of
current year taxable income, an indefinite net operating loss carryforward, immediate deductions for certain new investments
instead of deductions for depreciation expense over time and the modification or repeal of many business deductions and credits.
We continue to examine the impact of this tax reform legislation, and as its overall impact is uncertain, we note that the Jobs Act
could adversely affect our business and financial condition. The impact of this tax reform legislation on holders of our common
stock is also uncertain and could be adverse.
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Risks Related to Our Indebtedness
Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business
prospects and our ability to make payments on our outstanding debt.
As of December 31, 2017, we had approximately $390.8 million of total long-term debt and additional borrowing
capacity of $474.1 million under CRP’s revolving credit facility (after giving effect to $0.9 million of outstanding letters of
credit). Our level of indebtedness could affect our operations in several ways, including the following:
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require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby
reducing the cash available to finance our operations and other business activities;
limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in
our business and the industry in which we operate;
increase our vulnerability to downturns and adverse developments in our business and the economy generally;
limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for
working capital, capital expenditures, acquisitions, general corporate or other expenses or to refinance existing
indebtedness;
place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and
engage in business combinations;
• make it more likely that a reduction in CRP’s borrowing base following a periodic redetermination could require
CRP to repay a portion of its then-outstanding bank borrowings;
• make us vulnerable to increases in interest rates as the indebtedness under CRP’s revolving credit facility may vary
with prevailing interest rates;
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place us at a competitive disadvantage relative to our competitors with lower levels of indebtedness in relation to
their overall size or less restrictive terms governing their indebtedness; and
• make it more difficult for CRP to satisfy its obligations under its debt and increase the risk that we may default on its
debt obligations.
CRP may incur substantial additional indebtedness, which could further exacerbate the risks that we may face.
Subject to the restrictions in the instruments governing CRP’s outstanding indebtedness (including CRP’s revolving credit
facility and senior notes), CRP and its subsidiaries may incur substantial additional indebtedness (including secured indebtedness)
in the future. Although the instruments governing CRP’s outstanding indebtedness do contain restrictions on the incurrence of
additional indebtedness, these restrictions will be subject to waiver and a number of significant qualifications and exceptions, and
indebtedness incurred in compliance with these restrictions could be substantial. As of December 31, 2017, CRP had additional
borrowing capacity of $474.1 million under its revolving credit facility (after giving effect to $0.9 million of outstanding letters of
credit), all of which would be secured if borrowed.
Any increase in CRP’s level of indebtedness will have several important effects on our future operations, including, without
limitation:
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we will have additional cash requirements in order to support the payment of interest on CRP’s outstanding
indebtedness;
increases in CRP’s outstanding indebtedness and leverage will increase our vulnerability to adverse changes in
general economic and industry conditions, as well as to competitive pressure; and
depending on the levels of CRP’s outstanding indebtedness, our ability to obtain additional financing for working
capital, capital expenditures, general corporate and other purposes may be limited.
We may not be able to generate sufficient cash to service all of CRP’s indebtedness and may be forced to take other actions to
satisfy CRP’s obligations under applicable debt instruments, which may not be successful.
CRP’s ability to make scheduled payments on or to refinance its 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 CRP to pay the principal, premium, if any, and interest on CRP’s indebtedness.
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If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay
investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to
restructure or refinance CRP’s 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 CRP 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 CRP’s 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. The agreements
governing CRP’s indebtedness restrict CRP’s ability to dispose of assets and CRP’s use of the proceeds from such disposition.
CRP 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 CRP 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 and the indenture governing its senior notes contain a number of significant covenants, including
restrictive covenants that may limit CRP’s ability to, among other things:
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incur additional indebtedness;
• make loans to others;
• make investments;
• merge or consolidate with another entity;
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hedge future production or interest rates;
incur liens;
sell assets; and
engage in certain other transactions without the prior consent of the lenders.
In addition, CRP’s credit agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are
unable to comply with such ratios. As of December 31, 2017, we were in full compliance with such financial ratios and covenants.
The restrictions in CRP’s debt agreements 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 imposed on
CRP.
A breach of any covenant in CRP’s debt agreements 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.
If CRP is unable to comply with the restrictions and covenants in the agreements governing its indebtedness, there could be a
default under the terms of these agreements, which could result in an acceleration of payment of funds that CRP has
borrowed.
Any default under the agreements governing CRP’s indebtedness that is not cured or waived by the required lenders, and the
remedies sought by the holders of any such indebtedness, could make CRP unable to pay principal, premium, if any, and interest
on such indebtedness. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet
required payments of principal, premium, if any, and interest on CRP’s indebtedness, or if CRP otherwise fails to comply with the
various covenants, including financial and operating covenants, in the agreements governing CRP’s indebtedness, CRP could be
in default under the terms of the agreements governing such indebtedness. In the event of such default:
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the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable,
together with accrued and unpaid interest;
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the lenders under CRP’s revolving credit facility could elect to terminate their commitments thereunder, cease
making further loans and institute foreclosure proceedings against our assets; and
we could be forced into bankruptcy or liquidation.
If our operating performance declines, we may in the future need to obtain waivers under CRP’s revolving credit facility to
avoid CRP being in default. If CRP breaches the covenants under its revolving credit facility and seeks a waiver, CRP may not be
able to obtain a waiver from the required lenders. If this occurs, CRP would be in default under the revolving credit facility, the
lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.
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. 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. The borrowing base
under the revolving credit facility is $575 million; however, on December 1, 2017, CRP entered into an amendment to the credit
agreement to, among other things, reflect CRP’s election to voluntarily reduce the commitments and borrowing base under the
credit agreement to $475.0 million.
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.
If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and
negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the
credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current
ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating
agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset
purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product
mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit
and increase our borrowing costs.
Risks Related to Our Class A Common Stock and Capital Structure
Our only significant asset is our current ownership of an approximate 94% 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 94% 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.
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We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of
Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our
investors may lose confidence in our reported information and our stock price may be negatively affected.
We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley Act”).
Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment
of our internal control over financial reporting. This section also requires that our independent registered public accounting firm
opine on those internal controls. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or
our auditors identify and report material weaknesses in internal control over financial reporting, the accuracy and timeliness of the
filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our
reported financial information, which could have a negative effect on the trading price of our Class A Common Stock. In addition,
a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of
fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these
requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.
We incur increased costs as a result of being a public company, which may significantly affect our financial condition.
We completed our initial public offering in February 2016. As a public company, we incur significant legal, accounting and
other expenses that we would not incur as a private company. We also incur costs associated with our public company reporting
requirements and with corporate governance requirements, including requirements under the Sarbanes-Oxley Act, as well as rules
implemented by the SEC and the Financial Industry Regulatory Authority. These rules and regulations increase our legal and
financial compliance costs and make some activities more time-consuming and costly. These rules and regulations make it more
difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced
policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more
difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.
If the price of our Class A Common Stock fluctuates significantly, your investment could lose value.
Although our Class A Common Stock is listed on The NASDAQ Capital Market, we cannot assure you that an active public
market will continue for our Class A Common Stock. If an active public market for our Class A Common Stock does not continue,
the trading price and liquidity of our Class A Common Stock will be materially and adversely affected. If there is a thin trading
market or “float” for our Class A Common Stock, the market price for our Class A Common Stock may fluctuate significantly
more than the stock market as a whole. Without a large float, our Class A Common Stock would be less liquid than the stock of
companies with broader public ownership and, as a result, the trading prices of our Class A Common Stock may be more volatile.
In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us.
Furthermore, the stock market is subject to significant price and volume fluctuations, and the price of our Class A Common Stock
could fluctuate widely in response to several factors, including:
Factors affecting the trading price of our Class A Common Stock may include:
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actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies
perceived to be similar to us;
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;
additions or departures of key personnel;
sales of substantial amounts of our Class A Common Stock by our directors, executive officers or significant
stockholders or the perception that such sales could occur; and
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general economic and political conditions such as recession; interest rate, fuel price, and international currency
fluctuations; and acts of war or terrorism.
The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the
quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur
without regard to specific operating performance. The price of our Class A Common Stock could fluctuate based upon factors that
have little or nothing to do with our company and these fluctuations could materially reduce our stock price.
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 beneficially own approximately 36% of our voting common stock. As long as Riverstone and its
affiliates 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 may not align with the interests of our other stockholders. Riverstone 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 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.
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:
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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;
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
41
•
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.
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.
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. While the outcome of these proceedings cannot be predicted with
certainty, 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
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Price Range of Class A Common Stock
Our Class A Common Stock is currently quoted on NASDAQ under the symbol “CDEV.” 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:
2017:
Fourth Quarter
Third Quarter
Second Quarter
First Quarter
2016:
Fourth Quarter
Third Quarter
Second Quarter(1)
First Quarter(2)
Class A Common Stock
(CDEV)
High
Low
$
$
22.11
$
19.32
20.44
20.08
20.97
$
16.10
10.70
N/A
17.48
14.21
14.10
16.59
13.31
9.65
9.65
N/A
(1)
(2)
Beginning on April 15, 2016.
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 February 20, 2018, there were 191 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.
43
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 financial statements included in this Annual Report on Form 10-
K. The Company’s historical results are not necessarily indicative of future operating results.
On October 11, 2016, the Company 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 Company currently owns an approximate 94% membership interest in CRP due to various equity
transactions. The financial statement presentation distinguishes CRP as an accounting “Predecessor” for periods prior to the
Business Combination. Centennial is the “Successor” for periods after the Business Combination, which includes consolidation of
CRP subsequent to the Business Combination. Except as the context otherwise requires, references in the following discussion to
the “Company” or “Centennial” with respect to periods prior to the closing of the Business Combination are to CRP and its
operations before the Business Combination.
The following table shows selected historical financial information of CRP for the periods and as of the dates indicated
below. 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.
(in thousands, except per share, production and
per BOE data)
Statements of Operations Data:
Total revenues
Net income (loss) attributable to common
shareholders
Income (loss) per share:
Successor
Year Ended
December 31,
2017 (1)(3)
October 11,
2016
through
December 31,
2016(2)(3)
January 1,
2016
through
October 10,
2016(5)
Predecessor
Year Ended December 31,
2015(4)
2014(4)(5)
2013(4)(5)
$
429,902
$
29,717
$
69,116
$
90,460
$
131,825
$
71,974
75,568
(8,081)
(218,724)
(38,325)
17,790
3,618
Basic
Diluted
Cash Flows Data:
Net cash provided by operating activities
$
$
$
0.32
0.32
259,918
$
$
$
(0.05)
(0.05)
9,410
$
51,740
$
68,882
$
97,248
$
13,416
Net cash used by investing activities
(992,306)
(1,749,733)
(101,434)
(198,635)
(163,380)
(136,517)
Net cash provided by financing activities
724,220
1,874,268
47,926
118,504
36,966
118,742
(in thousands)
Balance Sheet Data:
Total assets
Long-term debt
Total equity
Dividends per share
Successor
Predecessor
December 31,
2017(1)(3)
December 31,
2016(2)(3)
December 31,
2015(4)
December 31,
2014(4)(5)
December 31,
2013(4)(5)
$
3,616,569
390,764
3,003,972
—
$ 2,651,642
—
2,552,935
—
$
$
616,295
138,649
450,864
—
$
615,769
129,568
377,932
—
472,085
29,000
390,547
—
(1) The results are impacted by the GMT Acquisition, which occurred in June 2017. See Note 3—Property Acquisitions, in Item 8 of Part
II of this Annual Report on Form 10-K for detailed information on the GMT Acquisition.
(2) The results are impacted by the Business Combination which occurred in October 2016. See Note 2—Business Combination, in Item 8
of Part II of this Annual Report on Form 10-K for detailed information on the Business Combination.
(3) The results are impacted by the Silverback Acquisition, which occurred in December 2016. See Note 3—Property Acquisitions, in Item
8 of Part II of this Annual Report on Form 10-K for detailed information on the Silverback Acquisition.
(4) 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.
(5) 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 reflects the combined results of CRP and Celero, and for all periods and dates subsequent to October
15, 2014, reflects the results of CRP.
44
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 financial statements and related notes in “Part II, Item 8. Financial Statements and Supplementary Data.” The
following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and
expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside
our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that
could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs,
production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes
and other uncertainties, as well as those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements”
and “Part I, Item 1A. Risk Factors” in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these
risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to
publicly update any forward-looking statements except as otherwise required by applicable law.
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 capital programs are specifically focused on projects that we believe provide the greatest potential for repeatable
success and return on capital.
Market Conditions
The oil and natural 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 through 2016, global
and domestic oil supply continued to outpace demand resulting in further deterioration in realized oil prices. In 2017, commodity
prices continued to be volatile, and it is likely that commodity prices will continue to fluctuate due to global supply and demand,
inventory supply levels, weather conditions, geopolitical and other factors.
The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter
of 2015:
2015
2016
2017
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Crude Oil (per Bbl)
$48.62
$57.84
$ 46.60
$ 42.16
$ 33.49
$ 45.70
$ 45.00
$ 49.27
$51.82
$ 48.32
$ 48.17
$ 55.31
Natural Gas (per MMBtu) $ 2.81
$ 2.74
$ 2.73
$ 2.24
$ 1.98
$ 2.25
$ 2.80
$
3.17
$ 3.06
$ 3.14
$ 2.95
$ 2.91
Although oil and natural gas prices have begun to recover from the lows experienced during the first quarter of 2016, forecast
prices for both oil and natural gas have not rebounded to 2014 levels. A sustained drop in oil, natural gas and NGL prices may not
only decrease our revenues on a per unit basis but may also reduce the amount of oil, natural gas and NGLs that we can produce
economically and therefore potentially lower our oil, natural gas and NGL reserve quantities.
Lower commodity prices in the future could result in impairments of our proved oil and natural gas properties or
undeveloped acreage 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 commodity prices may also reduce the
borrowing base under CRP’s credit agreement, which is determined at the discretion of the lenders and is based on the collateral
value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of the
revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under the
credit agreement.
2017 Highlights and Future Considerations
Operational Highlights
For the year ended December 31, 2017, we operated, on average, a six-rig drilling program and completed 70 gross operated
productive wells. This total number of completed wells had an average effective lateral length of approximately 5,700 feet.
Acquisition and Divestiture Highlights
On June 8, 2017, we completed the GMT Acquisition, which consisted of interests in 36 gross producing horizontal wells
plus approximately 11,850 undeveloped net acres in the core of the Northern Delaware Basin in Lea County, New Mexico for an
unadjusted purchase price of $350.0 million.
45
On February 8, 2018, we completed the acquisition of approximately 4,000 undeveloped net acres, as well as certain
producing properties, also in the core of the Northern Delaware Basin in Lea County, New Mexico for an unadjusted purchase
price of $94.7 million. The operated acreage position contains an average 95% working interest and is largely contiguous to
Centennial’s existing position.
On January 5, 2018, we entered into a purchase and sale agreement to sell approximately 8,600 undeveloped net acres and 12
gross producing wells located in Reeves County, Texas for a total sale price of $140.7 million, which is subject to certain post-
closing adjustments. The transaction is expected to close on March 1, 2018. The divested acreage represents a largely non-
operated position (average 32% WI) on the western portion of Centennial’s position in Reeves County. The properties to be
divested consist of 1,987 MBoe of proved reserves as of December 31, 2017, representing approximately 1% of our proved
reserves as of that date, and generated 235 Boe/d (less than 1%) of our 2017 average daily net production.
Financing Highlights
In connection with the GMT Acquisition in June 2017, we issued and sold in a private placement 23,500,000 shares of our
Class A Common Stock to certain institutional investors, which resulted in gross proceeds of approximately $340.8 million, and
such proceeds were used to fund the majority of the acquisition purchase price.
In November 2017, CRP issued at par $400.0 million of 5.375% senior notes due 2026 (the “Senior Notes”) in an 144A private
placement that resulted in net proceeds to CRP of $391 million, after deducting $9 million in debt issuance costs. The net proceeds
from this offering were used to repay all outstanding borrowings under the revolving credit facility and for general corporate purposes.
In connection with the October 2017 semi-annual redetermination on November 2, 2017, the Company entered into the fifth
amendment to the restated credit agreement to increase the borrowing base from $350.0 million to $575.0 million. However,
simultaneous with the issuance of the Senior Notes discussed above, we paid down all borrowings outstanding under our credit
facility and entered into the sixth amendment to the credit agreement on December 1, 2017, which enabled us to voluntarily
reduce the commitments and borrowing base under the credit agreement to $475.0 million.
Tax Reform
New tax legislation (commonly referred to as the “Jobs Act”) was enacted on December 22, 2017. Financial Accounting
Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 740, Accounting for Income Taxes requires companies to
recognize the effect of tax law changes in the period of enactment even though the effective date for most provisions is for tax
years beginning after December 31, 2017. Adjustments to our tax provision that were recorded in the three months ended
December 31, 2017 principally relate to the reduction in the U.S. corporate income tax rate to 21%, which resulted in the
Company recognizing an income tax benefit of $4.4 million to measure deferred taxes liabilities that will reverse at the new 21%
rate. Other significant provisions of the Jobs Act that are not yet effective but may impact income taxes in future years include: (i)
the limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income, (ii) a limitation of
net operating losses generated after fiscal 2018 to 80% of taxable income and the unlimited carryforward of such losses, (iii)
temporary 100% expensing of certain business assets, (iv) additional limitations on certain general and administrative expenses
and (v) changes in determining the excessive compensation limitation. Currently, we do not anticipate paying cash federal income
taxes in the near term due to any of the legislative changes, primarily due to our ability to expense intangible drilling costs and the
utilization of our net operating loss carryforwards.
46
Results of Operations
On October 11, 2016, the Company consummated the acquisition of approximately 89% of the outstanding membership
interests in CRP (the “Business Combination”). The Company currently owns an approximate 94% membership interest in CRP
due to various equity transactions. The financial statement presentation distinguishes CRP as an accounting “Predecessor” for
periods prior to the Business Combination. Centennial is the “Successor” for periods after the Business Combination, which
includes consolidation of CRP subsequent to the Business Combination. Except as the context otherwise requires, references in
the following discussion to the “Company” or “Centennial” with respect to periods prior to the closing of the Business
Combination are to CRP and its operations before the Business Combination.
For the Year Ended December 31, 2017 (Successor) Compared to Periods From October 11, 2016 Through December 31, 2016
(Successor) and January 1, 2016 Through October 10, 2016 (Predecessor) Combined
Oil, Natural Gas and NGL Sales Revenues. The following table provides the components of net revenues and net production
(net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s
respective average prices and production volumes:
Successor
Predecessor
Combined
Year Ended
December 31,
2017
October 11, 2016
through
December 31, 2016
January 1, 2016
through
October 10, 2016
Year Ended
December 31,
2016
2017 Successor vs.
2016 Combined
$
%
336,931
$
24,313
$
59,787
$
84,100
$ 252,831
48,868
44,103
429,902
$
3,449
1,955
29,717
6,045
3,284
9,494
5,239
39,374
38,864
69,116
$
98,833
$ 331,069
301 %
415 %
742 %
335 %
Net revenues (in thousands):
Oil sales
Natural gas sales
NGL sales
Total net revenues
Average sales price:
Oil (per Bbl)
Effect of derivative settlements on
average price (per Bbl)
Oil net of hedging (per Bbl)
Average NYMEX price for oil (per
Bbl)
Natural gas (per Mcf)
Effect of derivative settlements on
average price (per Mcf)
$
$
$
$
$
$
48.17
$
(0.06)
48.11
$
$
$
50.88
2.75
—
Natural gas net of hedging (per Mcf)
$
2.75
$
Average NYMEX price for natural
gas (per Mcf)
NGL (per Bbl)
Net production:
Oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Total (MBoe)
Average daily net production volume:
Oil (Bbls/d)
Natural gas (Mcf/d)
NGLs (Bbls/d)
Total (Boe/d)
$
$
3.02
26.28
$
$
6,994
17,754
1,678
11,630
19,161
48,640
4,596
31,864
$
$
$
$
$
$
$
$
46.49
2.02
48.51
49.21
3.10
—
3.10
3.18
20.36
523
1,113
96
805
6,378
13,573
1,171
9,811
47
37.74
$
39.91
$
8.26
21 %
10.49
8.39
48.23
$
48.30
$
(8.45)
(0.19)
(101)%
— %
$
$
41.75
2.27
—
$
$
43.43
2.52
—
7.45
17 %
0.23
9 %
2.27
$
2.52
$
0.23
9 %
2.37
12.98
$
$
2.55
15.01
$
$
0.47
18 %
11.27
75 %
1,584
2,660
253
2,280
5,577
9,366
891
8,029
2,107
3,773
349
3,085
5,757
10,309
954
8,429
4,887
13,981
1,329
8,545
13,404
38,331
3,642
23,435
232 %
371 %
381 %
277 %
233 %
372 %
382 %
278 %
Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the year ended December 31, 2017 (Successor) were
$331.1 million (or 335%) higher than total net revenues for the combined year ended December 31, 2016. Revenues are a
function of oil, natural gas and NGL volumes sold and average commodity sales prices realized.
Net production volumes for oil, natural gas, and NGLs increased 232%, 371% and 381%, respectively, between periods. The
oil volume increase between periods resulted primarily from drilling success in the Delaware Basin, as well as producing
properties acquired in the Silverback and GMT Acquisitions, which collectively added 801 MBbls of net oil production in 2017.
During the year ended December 31, 2017, 70 gross operated wells were placed on production in the Delaware Basin, which
added 4,346 MBbls of net oil production. The increase in the Company’s operated well count is attributable to the ramp up of its
drilling program starting in the fourth quarter of 2016. These oil volume increases were partially offset by normal production
declines across existing wells. Natural gas and NGLs are produced concurrently with crude oil volumes, resulting in a high
correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. Natural gas and NGL volumes
were additionally impacted by the acreage acquired from Silverback, which has a higher gas/oil ratio. During the year ended
December 31, 2017, production mix consisted of 40% natural gas and NGL volumes as compared to 32% in 2016.
In addition to production-related increases in net revenue between periods, there were also significant increases in average
realized sales prices for oil, natural gas and NGLs when comparing the year ended December 31, 2017 to 2016. The average
realized price for oil before the effects of hedging increased 21%, the average realized price for natural gas before the effects of
hedging increased 9%, and the average realized price for NGLs increased 75% between periods. Of the 21% increase in the
average realized oil price, 17% of such increase was related to higher average NYMEX crude prices between periods, and the
remaining 4% was attributable to narrower oil differentials in 2017. The 9% increase in the average realized natural gas price was
similarly related to higher NYMEX prices between periods (NYMEX natural gas prices being up 18% between periods) which
was partially offset by wider gas differentials experienced during the year ended December 31, 2017. Of the overall 75% increase
in average realized NGL prices between periods, the majority of such increase was related to higher average Mont Belvieu spot
prices for plant products during the year ended December 31, 2017. Additionally, NGL prices increased beginning in August 2016
as a result of lower transportation costs incurred by the Company’s gas processor due to the use of pipeline versus prior trucking
alternatives.
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
Successor
Predecessor
Combined
Year Ended
December 31,
2017
October 11, 2016
through
December 31, 2016
January 1, 2016
through
October 10, 2016
Year Ended
December 31,
2016
2017 Successor vs. 2016
Combined
$
%
Operating Expenses (in thousands):
Lease operating expenses
$
41,336
$
Severance and ad valorem taxes
Gathering, processing, and
transportation expense
Production costs per Boe:
23,173
34,259
Lease operating expenses
$
Severance and ad valorem taxes
Gathering, processing, and
transportation expense
$
3.55
1.99
2.95
$
$
3,541
1,636
2,187
4.40
2.03
2.72
11,036
$
14,577
$
26,759
5,332
17,841
184 %
335 %
3,696
4,583
4.84
1.62
2.01
$
6,770
27,489
406 %
4.73
1.73
2.19
$
(1.18)
0.26
0.76
(25)%
15 %
35 %
Lease Operating Expenses. LOE for the year ended December 31, 2017 (Successor) increased $26.8 million compared to the
combined 2016 comparable period. Higher LOE for 2017 was primarily related to a $21.3 million increase associated with higher
well count. The Company added 70 gross operated wells through successful drilling and 57 gross operated wells from the
Silverback and GMT Acquisitions. In addition, workover activity increased $5.5 million between periods also as a result of higher
well count. The Company had 106 gross operated horizontal wells, which includes those added from the Silverback Acquisition,
as of December 31, 2016 as compared to 181 gross operated horizontal wells as of December 31, 2017.
LOE on a per Boe basis, on the other hand, decreased when comparing the year ended December 31, 2017 to the combined 2016
period. LOE per Boe was $3.55 for the year ended December 31, 2017, which represents a decrease of $1.18 per Boe (or 25%) from
the combined year ended December 31, 2016. This decrease in rate was mainly due to flush production from new wells drilled and
completed over the past 12 months, which has the effect of reducing fixed and semi-variable costs on a per Boe basis.
Severance and Ad Valorem Taxes. Severance taxes are primarily based on the market value of production at the wellhead, and
ad valorem taxes are generally based on the valuation of oil and natural gas properties and vary across the different counties in
which the Company operates. Severance and ad valorem taxes for the year ended December 31, 2017 (Successor) increased $17.8
48
million (or 335%) compared to the 2016 combined period due to higher oil, natural gas and NGL revenues between years.
Severance and ad valorem taxes as a percentage of total net revenues remained consistent for the year ended December 31, 2017
and 2016 at 5.4%.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) for the year
ended December 31, 2017 (Successor) increased $27.5 million compared to the combined 2016 period due to higher natural gas
and NGL volumes sold between periods, which in turn resulted in a higher amount of plant processing fees and per unit
transportation and gathering costs being incurred between 2017 and 2016.
On a per Boe basis, GP&T increased 35% from $2.19 for the combined year ended December 31, 2016 to $2.95 per Boe for
the comparable 2017 period. This increase in rate was mainly attributable to the change in gas/oil ratio whereby a higher
percentage of total production was made up of natural gas and NGL volumes during the year ended December 31, 2017, and thus
a higher proportion of production during 2017 was subject to gas gathering and transportation charges as well as gas processing
fees. On a natural gas and NGL volumes basis (i.e. excluding crude oil barrels) the Boe rate increased only 7% between periods
from $6.92 to $7.39 for the years ended December 31, 2016 and 2017, respectively. This increase was primarily the result of a
new firm transportation agreement entered into in June 2017, which provides guaranteed pipeline capacity for the Company’s
natural gas production (refer to Note 13—Commitments and Contingencies in Item 8 of Part II of this Annual Report on Form 10-
K for additional information on such agreement).
Depreciation, Depletion, and Amortization. The following table summarizes DD&A for the periods indicated:
(in thousands)
Depreciation, depletion and amortization
Depreciation, depletion and amortization per Boe
Successor
Year Ended
December 31, 2017
161,628
October 11, 2016
through
December 31, 2016
14,877
$
13.90
$
18.48
Predecessor
January 1, 2016
through
October 10, 2016
$
$
62,964
27.62
DD&A rate can fluctuate as a result of development costs, acquisitions, impairments, as well as changes in proved reserves or
proved developed reserves. For the year ended December 31, 2017 (Successor), DD&A expense amounted to $161.6 million,
compared to $14.9 million for the period from October 11, 2016 through December 31, 2016 (Successor) and $63.0 million for
the period from January 1, 2016 through October 10, 2016 (Predecessor). The main factor contributing to higher DD&A expense
in 2017 was the increase in overall production volumes from 2016 to 2017, which was partially offset by the significantly lower
DD&A rate between periods.
DD&A per Boe was $13.90 for the year ended December 31, 2017 compared to $18.48 for the period from October 11, 2016
through December 31, 2016. The primary factor contributing to this lower DD&A rate was substantial additions to proved
reserves and proved developed reserves over the past 12 months, relative to reduced drilling and completion costs over that time
period. The higher rate of $27.62 for the Predecessor period from January 1, 2016 through October 10, 2016 was due to the
Company’s assets and liabilities being recorded at their respective fair values as a result as the Business Combination on October
2016.
Exploration Expense. The following table summarizes exploration expenses for the periods indicated:
(in thousands)
Stock-based compensation expense
Dry exploratory well costs
Geological and geophysical costs
Exploration expense
Successor
Year Ended
December 31, 2017
October 11, 2016
through
December 31, 2016
$
— $
Predecessor
January 1, 2016
through
October 10, 2016
—
—
920
920
—
1,468
1,468
$
1,609
5,658
7,106
14,373
$
Exploration expense was $14.4 million for the year ended December 31, 2017 (Successor) compared to $1.5 million for the
period from October 11, 2016 through December 31, 2016 (Successor) and $0.9 million for the period from January 1, 2016
through October 10, 2016 (Predecessor). Exploration expense mainly consists of costs of topographical studies, G&G projects,
and salaries and expenses of G&G personnel. The increase in exploration expense in 2017 is due to (i) increased G&G projects
and seismic studies (ii) $5.7 million in exploratory dry hole costs in 2017 with no dry hole costs in 2016, (iii) seven geologist
positions added since 2016, and (iv) equity-based compensation awards that were granted to G&G personnel in 2017.
49
$
$
$
$
General and Administrative Expenses. The following table summarizes G&A expenses for the periods indicated:
(in thousands)
Stock-based compensation expense
Cash general and administrative expenses
General and administrative expenses
Successor
Year Ended
December 31, 2017
12,150
$
37,732
49,882
$
October 11, 2016
through
December 31, 2016
1,333
$
11,758
13,091
$
$
$
Predecessor
January 1, 2016
through
October 10, 2016
—
24,661
24,661
G&A expenses for the year ended December 31, 2017 (Successor) were $49.9 million compared to $13.1 million for the
period from October 11, 2016 through December 31, 2016 (Successor) and $24.7 million for the period from January 1, 2016
through October 10, 2016 (Predecessor). The higher G&A expenses incurred in 2017 were primarily due to $15.1 million in
increased employee salaries and related payroll burdens, $10.8 million in higher stock-based compensation, and $3.5 million in
increased professional fees. Employee-related costs were substantially higher in 2017 due to the number of administrative
employees (i.e. non-billable to joint interest partners) increasing from 57 at December 31, 2016 to 119 as of December 31, 2017,
and professional fees were also higher due to costs associated with being a public company that were incurred during the 2017
period. These increases were partially offset by $4.1 million and $15.8 million of transactional expenses incurred during the
Successor and Predecessor 2016 periods, respectively, primarily attributable to the consummation of the Business Combination.
Other Income and Expenses.
Gain on Sale of Oil and Natural Gas Properties. During the year ended December 31, 2017 (Successor), a gain of $7.2
million was recorded on the sale of oil and gas properties in Pecos County, Texas as well as an additional gain of $1.6 million on
other sales of non-core properties in 2017.
Interest Expense. The following table summarizes interest expenses for the periods indicated:
(in thousands)
Credit Facility
Senior Notes
Term Loan
Financing obligation
Interest capitalized
Total
Successor
Year Ended
December 31, 2017
4,882
$
2,007
—
—
(1,160)
5,729
$
October 11, 2016
through
December 31, 2016
263
$
—
115
—
—
378
$
$
$
Predecessor
January 1, 2016
through
October 10, 2016
2,541
—
3,024
61
—
5,626
For the year ended December 31, 2017 (Successor), interest expense incurred was $5.7 million, which consisted of $4.9
million related to CRP’s credit facility and $2.0 million related to the Senior Notes partially offset by $1.2 million in capitalized
interest. For the period from October 11, 2016 through December 31, 2016 (Successor) interest expense incurred was $0.4
million, which mainly consisted of the commitment fee paid for unused amounts on CRP’s credit facility. For the period from
January 1, 2016 through October 10, 2016 (Predecessor), interest expense incurred was $2.5 million on borrowings under the
revolving credit facility and interest of $3.0 million on the term loan, which was extinguished upon closing of the Business
Combination.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of i) fluctuations in mark-to-market
derivative fair values associated with corresponding changes in underlying commodity prices and ii) monthly cash settlements of
hedged derivative positions. For the year ended December 31, 2017 (Successor), non-cash mark-to-market derivative gains of
$5.8 million and cash derivatives settlements losses of $0.7 million were recognized. For the periods from October 11, 2016
through December 31, 2016 (Successor) and January 1, 2016 through October 10, 2016 (Predecessor), non-cash mark-to-market
derivatives losses of $2.6 million and $23.5 million, respectively, and $1.1 million and $16.6 million, respectively, of cash
derivatives settlements gains were recognized.
Income Tax Expense. During the year ended December 31, 2017 (Successor) the Company recognized $29.9 million in
income tax expense. The Company's provision for income taxes for the year ended December 31, 2017 differed from the amount
that would be provided by applying the statutory U.S. federal tax rate of 35% to pre-tax income primarily because of (i) the $5.1
million benefit associated with the release of the valuation allowance that was previously recorded against our NOL
carryforwards, (ii) the $4.4 million benefit upon the enactment of the Jobs Act in December of 2017 which reduced the future
corporate tax rate to 21%, and (iii) permanent items of $3.0 million. These benefits were partially offset by higher effective state
50
income tax rates (refer to Note 6—Income Taxes in Item 8 of Part II of this Annual Report on Form 10-K for additional information on
income taxes).
For the Periods From October 11, 2016 Through December 31, 2016 (Successor) and January 1, 2016 Through October 10,
2016 (Predecessor) Combined Compared to Year Ended December 31, 2015 (Predecessor)
Oil, Natural Gas and NGL Sales Revenues. The following table provides the components of net revenues and net production
(net of all royalties, overriding royalties and production due to others) 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
2016 Combined vs
2015 Predecessor
$
%
Net revenues (in thousands):
Oil sales
Natural gas sales
NGL sales
Total net revenues
Average sales price:
Oil (per Bbl)
Effect of derivative settlements on
average price (per Bbl)
Oil net of hedging (per Bbl)
Average NYMEX price for oil (per
Bbl)
Natural gas (per Mcf)
Effect of derivative settlements on
average price (per Mcf)
Natural gas net of hedging (per Mcf)
Average NYMEX price for natural gas
(per Mcf)
NGL (per Bbl)
Net production:
Oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Total (MBoe)
Average daily net production
volume:
Oil (Bbls/d)
Natural gas (Mcf/d)
NGLs (Bbls/d)
Total (Boe/d)
$
$
$
$
$
$
$
$
$
$
$
$
$
24,313
3,449
1,955
29,717
46.49
2.02
48.51
49.21
3.10
—
3.10
3.18
20.36
523
1,113
96
805
6,378
13,573
1,171
9,811
$
$
$
$
$
$
$
$
$
$
$
$
$
59,787
$
84,100
$
77,643
$
6,457
6,045
3,284
9,494
5,239
7,965
4,852
1,529
387
69,116
$
98,833
$
90,460
$
8,373
8 %
19 %
8 %
9 %
37.74
$
39.91
$
42.43
$
(2.52)
(6)%
10.49
8.39
19.18
(10.79)
48.23
$
48.30
$
61.61
$ (13.31)
(56)%
(22)%
$
$
41.75
2.27
—
$
$
43.43
2.52
—
2.27
$
2.52
$
48.76
2.60
0.43
3.03
$
$
(5.33)
(11)%
(0.08)
(3)%
(0.43)
(100)%
$
(0.51)
(17)%
2.37
12.98
$
$
2.55
15.01
$
$
2.63
14.66
$
$
(0.08)
(3)%
0.35
2 %
1,584
$
2,107
$
1,830
$
2,660
253
3,773
349
3,058
331
2,280
$
3,085
$
2,671
$
277
715
18
414
5,577
$
5,757
$
5,014
$
743
9,366
891
10,309
954
8,378
907
1,931
47
8,029
$
8,429
$
7,317
$
1,112
15 %
23 %
5 %
15 %
15 %
23 %
5 %
15 %
The 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 6% and 3% decrease in average sales price for
oil and natural gas, respectively, compared to the prior year.
51
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.
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
2016 Combined vs
2015 Predecessor
$
%
Operating Expenses (in thousands):
Lease operating expenses
Severance and ad valorem taxes
Gathering, processing, and
transportation expense
Production costs per Boe:
Lease operating expenses
Severance and ad valorem taxes
Gathering, processing, and
transportation expense
$
$
$
$
3,541
1,636
2,187
4.40
2.03
2.72
11,036
$
14,577
$
21,173
$ (6,596)
5,021
311
(31)%
6 %
3,696
4,583
4.84
1.62
2.01
$
5,332
6,770
4.73
1.73
2.19
$
5,732
1,038
18 %
7.93
1.88
2.15
$
(3.20)
(0.15)
(40)%
(8)%
0.04
2 %
Lease Operating Expenses. 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 the Company 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, the use of contract labor and expenses related to repairs and maintenance decreased 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 production at the wellhead and
ad valorem taxes are generally based on the valuation of oil and natural gas properties and vary across the different counties in
which the Company operates. 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 revenue were 5.4% for 2017 compared to 5.6% for the prior year period.
Gathering, Processing and Transportation 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, and Amortization. The following table summarizes DD&A for the periods indicated:
(in thousands)
Depreciation, depletion and amortization
Depreciation, depletion and amortization per Boe
Successor
October 11, 2016
through
December 31, 2016
14,877
$
Predecessor
January 1, 2016
through
October 10, 2016
Year Ended
December 31, 2015
$
62,964
$
18.48
27.62
90,084
33.73
DD&A rate can fluctuate as a result of impairments, dispositions, finding and development costs and proved reserve volumes.
For the period from October 11, 2016 through December 31, 2016 (Successor), DD&A expense for the period was $14.9 million
or $18.48 per Boe.
For the period from January 1, 2016 through October 10, 2016 (Predecessor), DD&A expense was $63.0 million or $27.62
per Boe. In 2015, DD&A expense was $90.1 million or $33.73 per Boe. The decrease in DD&A rate is primarily due to lower
development costs and reserve additions.
52
Abandonment Expense and Impairment of Unproved Properties. The following table summarizes abandonment expense and
impairment of unproved properties for the periods indicated:
(in thousands)
Abandonment expense and impairment of unproved properties
Successor
October 11, 2016
through
December 31, 2016
—
$
Predecessor
January 1, 2016
through
October 10, 2016
Year Ended
December 31, 2015
$
2,545
$
7,619
For the period from October 11, 2016 through December 31, 2016 (Successor), there were no abandonment expense or
impairment of unproved property. For the period from January 1, 2016 through October 10, 2016 (Predecessor) and in 2015,
impairment of unproved properties was $2.5 million and $7.6 million, respectively, related to leases that expired during the period
or are expected to expire in the future.
Exploration. The following table summarizes exploration expense for the periods indicated:
(in thousands)
Exploration
Successor
October 11, 2016
through
December 31, 2016
1,468
$
Predecessor
January 1, 2016
through
October 10, 2016
Year Ended
December 31, 2015
$
920
$
84
For the period from October 11, 2016 through December 31, 2016 (Successor), exploration expense was $1.5 million related
to seismic data and salaries and expenses of G&G personnel and consultants. For the period from January 1, 2016 through
October 10, 2016 (Predecessor), exploration expense was $0.9 million related to salaries and expenses of G&G personnel and
consultants. For 2015, explorations expense was $0.1 million related to logging analyses.
Contract Termination and Rig Stacking. The following table summarizes contract termination and rig stacking expenses for
the periods indicated:
(in thousands)
Contract termination and rig stacking
Successor
October 11, 2016
through
December 31, 2016
—
$
Predecessor
January 1, 2016
through
October 10, 2016
Year Ended
December 31, 2015
$
— $
2,387
For the periods from October 11, 2016 through December 31, 2016 (Successor) and January 1, 2016 through October 10,
2016 (Predecessor), there were no drilling and rig termination fees incurred as compared to $2.4 million in 2015. In light of the
low commodity price environment, drilling activity was curtailed beginning in the first quarter of 2015, and as a result, drilling
and rig termination fees were incurred of $2.4 million in 2015.
General and Administrative Expenses. The following table summarizes G&A expenses for the periods indicated:
(in thousands)
General and administrative expenses
Successor
October 11, 2016
through
December 31, 2016
13,091
$
Predecessor
January 1, 2016
through
October 10, 2016
Year Ended
December 31, 2015
$
24,661
$
14,206
For the period from October 11, 2016 through December 31, 2016 (Successor), G&A expenses were $13.1 million. G&A
expenses for the Successor period included $4.1 million of transactional expenses primarily attributable to the consummation of
the Business Combination. Additionally, G&A expenses for the Successor period included $1.0 million of non-cash charges
resulting from the issuance of restricted stock and stock option awards.
For the period from January 1, 2016 through October 10, 2016 (Predecessor), G&A expenses were $24.7 million. In 2015,
G&A expenses were $14.2 million. G&A expenses increased 74%, or $10.5 million, between these two periods primarily due to
$15.8 million of transaction expenses incurred in connection with the Business Combination during the period from January 1,
2016 through October 10, 2016.
53
Incentive Compensation. The following table summarize incentive compensation for the period indicated:
(in thousands)
Incentive unit compensation
Successor
October 11, 2016
through
December 31, 2016
—
$
Predecessor
January 1, 2016
through
October 10, 2016
Year Ended
December 31, 2015
$
165,394
$
—
For the period from January 1, 2016 through October 10, 2016 (Predecessor), non-cash incentive compensation was $165.4
million related to the consummation of the Business Combination. Refer to Note 8—Stock-Based Compensation in Item 8 of Part II
of this Annual Report on Form 10-K for additional information regarding the inventive units.
Other Income and Expenses. The following table summarizes other income and expenses for the periods indicated:
(in thousands)
Other (expense) income:
Gain (loss) on sale of oil and natural gas properties
Interest expense
Net gain (loss) on derivative instruments
Other income
Total Other income (expense)
Income tax benefit
Successor
October 11, 2016
through
December 31, 2016
Predecessor
January 1, 2016
through
October 10, 2016
Year Ended
December 31, 2015
$
$
$
24
(378)
(1,548)
—
(1,902)
—
$
$
$
11
$
(5,626)
(6,838)
6
(12,447) $
406
$
2,439
(6,266)
20,756
20
16,949
572
Gain on Sale of Oil and Natural Gas Properties. For the periods from October 11, 2016 through December 31, 2016
(Successor) and January 1, 2016 through October 10, 2016 (Predecessor) net gains on the sale of oil and natural gas properties
were immaterial. In 2015 (Predecessor), net gains on the sale of oil and natural gas properties was $2.4 million, which was
primarily attributable to a gain associated with the sale of non-core unproved property to an unrelated third party.
Interest Expense. For the period from October 11, 2016 through December 31, 2016 (Successor) interest expense was $0.4
million primarily related to the commitment fee paid for unused amounts on the revolving credit facility. For the period from
January 1, 2016 through October 10, 2016 (Predecessor), interest expense was $5.6 million related to borrowings under the
revolving credit facility and interest on the term loan. In 2015 (Predecessor), interest expense was $6.3 million related to
borrowings under the revolving credit facility and interest on the term loan.
Net Gain (Loss) on Derivative Instruments. For the periods from October 11, 2016 through December 31, 2016 (Successor)
and January 1, 2016 through October 10, 2016 (Predecessor), derivatives losses of $1.5 million and $6.8 million, respectively,
were incurred. In 2015 (Predecessor), a derivative gain of $20.8 million was recognized. Net losses and gains on derivatives are a
function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.
Liquidity and Capital Resources
Overview
Our development and acquisition activities require us to make significant operating and capital expenditures. Historically, our
primary sources of liquidity have been borrowings under CRP’s revolving credit facility, cash flows from operations and offerings
of debt and equity securities and, prior to the Business Combination, capital contributions from CRP’s Sponsors. To date, our
primary use of capital has been for development and the acquisition of oil and natural gas properties.
The following table summarizes our capital expenditures incurred during the year:
(in millions)
Drilling and completion capital expenditures
Land and other
Facilities, seismic and other
Total capital expenditures
54
Year Ended
December 31, 2017
$
$
624.1
55.1
17.2
696.4
We continually evaluate our capital needs and compare them to our capital resources. Our estimated capital expenditure
budget for 2018 is $885 million to $1,050 million, of which $710 million to $820 million is related to drilling and completion
(“D&C”) activity. We expect to fund the capital expenditure budget with cash flows from operations and borrowings. The D&C
portion of our 2018 capital budget represents an increase over the $624.1 million of D&C expenditures incurred during 2017. This
increased 2018 capital budget is driven by an increase in rig activity from six to seven rigs, the concomitant increase in
anticipated wells drilled and completed compared to 2017, and the increase in the number of extended lateral wells drilled which
require more capital than shorter laterals.
Because we are the operator of a high percentage of our acreage, the amount and timing of these capital expenditures are
largely discretionary. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors,
including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the
availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and
approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners.
Based upon current oil and natural gas price expectations in the year 2018, we believe that our cash flow from operations and
borrowings will provide us with sufficient liquidity to execute our current capital program. However, future cash flows are subject
to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital
expenditures will be required to more fully develop our properties. We cannot ensure that cash flows from operations and other
needed capital will be available on acceptable terms or at all. In the event we make additional acquisitions and the amount of
capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the
expected level of capital expenditures and/or seek additional sources for funding capital investments. As we pursue our future
development program, we continually assess the correct mix of reserve base borrowings and debt offerings. If we require
additional capital to fund acquisitions, we may also seek such capital through traditional reserve base borrowings, offerings of
debt and equity securities, asset sales or other means. If we are unable to obtain funds when needed or on acceptable terms, we
may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In
addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to
maintain our production or replace our reserves.
Analysis of Cash Flow Changes
The following table summarizes our cash flows for the periods indicated:
(in thousands)
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
Successor
Predecessor
Year Ended
December 31, 2017
259,918
$
(992,306)
724,220
October 11, 2016
through
December 31, 2016
9,410
$
(1,749,733)
1,874,268
January 1, 2016
through
October 10, 2016
51,740
$
(101,434)
47,926
Year Ended
December 31, 2015
68,882
$
(198,635)
118,504
Total cash, cash equivalents and restricted cash were $125.9 million as of December 31, 2017, which includes $8.6 million of
restricted cash. We generated $259.9 million of cash from operating activities, which was the results of continued higher
production activities and realized prices partially offset by increased operating expenses. Cash from operating activities was used
with cash on hand and $390.8 million net proceeds from the Senior Notes offering to finance $566.4 million for drilling and
development capital expenditures and repay borrowings under our credit facility. Net proceeds of $333.5 million from the
issuance of Class A Common Stock together with cash on hand, $35.0 million in net borrowings under the credit facility and
proceeds from the sale of oil and gas properties were used to finance $435.5 million in oil and gas property acquisitions including
the GMT Acquisition and the remainder of the Silverback Acquisition.
Total cash and cash equivalents were $134.1 million as of December 31, 2016. Cash flows from October 11, 2016 through
December 31, 2016 were significantly impacted by the acquisition of CRP for $1,375.7 million, $822.7 million for the Silverback
Acquisition, $26.9 million in acquisitions of oil and natural gas properties and $24.1 million for drilling and development capital
expenditures which were financed by cash on hand, cash flows from operating activities, $1,540.6 million net proceeds from the
issuance of Class A Common Shares and $379.5 million net proceeds from the issuance of Preferred Series B Shares.
Cash flows from January 1, 2016 through October 11, 2016 primarily relate to $55.6 million in acquisitions of oil and natural
gas properties and $45.6 million for drilling and development capital expenditures, which were financed by cash on hand, $51.7
million cash flows generated from operating activities and $50.0 million in net borrowings under our credit facility.
Total cash and cash equivalents were $1.8 million as of December 31, 2015. The major use of our funds included $43.2
million in acquisitions of oil and natural gas properties and $156.0 million for drilling and development capital expenditures,
55
which were financed by $68.9 million cash flows from operating activities, cash on hand, borrowings from our credit facility and
$111.4 million capital contributions.
Credit Agreement
CRP, the Company’s consolidated subsidiary, has a credit agreement with a syndicate of banks that as of December 31, 2017,
had a borrowing base of $475.0 million, which has been committed by lenders and is available for borrowing. A portion of the
revolving credit facility in an aggregate amount not to exceed $15.0 million may be used to issue letters of credit for the account
of CRP or other designated subsidiaries of the Company. As of December 31, 2017, the Company had no borrowings outstanding
and $474.1 million in available borrowing capacity, which was net of $0.9 million in letters of credit outstanding. The revolving
credit facility is scheduled to mature in October 2019 and the Company expects to enter into a new credit agreement in the spring
of 2018.
The amount available to be borrowed under CRP's revolving credit facility is subject to a borrowing base that is redetermined
semi-annually each April 1 and October 1 by the lenders in their sole discretion. CRP's credit agreement also allows
for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things,
the volumes of CRP’s proved oil and natural gas reserves, estimated cash flows from these reserves and its commodity hedge
positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of
permitted issued senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing
base, if borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a
portion of its debt outstanding under the credit agreement. Borrowings under CRP’s revolving credit facility are guaranteed by
certain of its subsidiaries. In connection with the October 2017 semi-annual redetermination, on November 2, 2017, the credit
agreement’s borrowing base was increased from $350.0 million to $575.0 million; however, on December 1, 2017 simultaneous
with the issuance of the Senior Notes, CRP entered into an amendment to the credit agreement to, among other things, reflect
CRP’s election to voluntarily reduce the commitments and borrowing base under the credit agreement to $475.0 million.
Borrowings under the revolving credit facility may be base rate loans or LIBOR loans. Interest is payable quarterly for base
rate loans and at the end of the applicable interest period for LIBOR loans. LIBOR loans bear interest at LIBOR (adjusted for
statutory reserve requirements) plus an applicable margin ranging from 225 to 325 basis points, depending on the percentage of
the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank's prime
rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate for a one-month interest period plus
100 basis points, plus an applicable margin ranging from 125 to 225 basis points, depending on the percentage of the borrowing
base utilized. CRP also pays a commitment fee on unused amounts of its revolving credit facility of 50 basis points. CRP may
repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage
costs. CRP also pays a commitment fee on unused amounts of its revolving credit facility of 50 basis points. CRP may repay any
amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.
CRP’s credit agreement contains restrictive covenants that limit its ability to, among other things: incur additional
indebtedness; make investments and loans; enter into mergers; make or declare dividends; enter into commodity hedges
exceeding a specified percentage of its expected production; enter into interest rate hedges exceeding a specified percentage of its
outstanding indebtedness; incur liens; sell assets; and engage in transactions with affiliates.
CRP’s credit agreement also requires it to maintain compliance with the following financial ratios: (i) a current ratio, which is
the ratio of CRP’s consolidated current assets (including unused commitments under its revolving credit facility and excluding
non-cash assets under FASB’s ASC Topic 815, Derivatives and Hedging (“ASC 815”), and certain restricted cash) to its
consolidated current liabilities (excluding the current portion of long-term debt under the credit agreement and non-cash liabilities
under ASC 815), of not less than 1.0 to 1.0; and (ii) a leverage ratio, which is the ratio of Total Funded Debt (as defined in CRP’s
credit agreement) to consolidated EBITDAX (as defined in CRP’s credit agreement) for the rolling four fiscal quarter period
ending on such day, of not greater than 4.0 to 1.0.
CRP was in compliance with the covenants and the financial ratios described above as of December 31, 2017 and through the
filing of this report.
5.375% Senior Unsecured Notes due 2026
On November 30, 2017, CRP issued at par $400.0 million of 5.375% senior notes due 2026 (the “Senior Notes”) in an 144A
private placement that resulted in net proceeds to CRP of $391 million, after deducting $9 million in debt issuance costs. Interest
is payable on the Senior Notes semi-annually in arrears on each January 15 and July 15, commencing July 15, 2018. The Senior
Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of CRP’s current subsidiaries that guarantee
CRP’s revolving credit facility. The Senior Notes are not guaranteed by the Company nor is the Company subject to the terms of
the indenture governing the Senior Notes.
56
At any time prior to January 15, 2021, CRP may, on any one or more occasions, redeem up to 35% of the aggregate principal
amount of the Senior Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a
redemption price equal to 105.375% of the principal amount of the Senior Notes redeemed, plus accrued and unpaid interest, if
any, to the date of redemption; provided that at least 65% of the aggregate principal amount issued under the indenture governing
the Senior Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the
closing date of such equity offering.
At any time prior to January 15, 2021, CRP may, on any one or more occasions, redeem all or a part of the Senior Notes at a
redemption price equal to 100% of the principal amount of the Senior Notes redeemed, plus a “make-whole” premium as of, and
accrued and unpaid interest, if any, to, the date of redemption. On and after January 15, 2021, CRP may redeem the Senior Notes,
in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 102.688% for the 12-month
period beginning on January 15, 2021, 101.344% for the 12-month period beginning on January 15, 2022 and 100% beginning on
January 15, 2023, plus accrued and unpaid interest to the redemption date.
If CRP experiences certain defined changes of control, each holder of the Senior Notes may require CRP to repurchase all or
a portion of its Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes, plus any
accrued but unpaid interest to the date of repurchase.
The indenture governing the Senior Notes contains covenants that, among other things and subject to certain exceptions and
qualifications, limit CRP’s ability and the ability of CRP’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness
or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or
subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements
that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all
of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with
the covenants as of December 31, 2017 and through the filing of this report.
Upon an Event of Default (as defined in the indenture governing the Senior Notes), the trustee or the holders of at least 25%
of the aggregate principal amount of then outstanding Senior Notes may declare the Senior Notes immediately due and payable,
except that a default resulting from certain events of bankruptcy or insolvency with respect to CRP, any restricted subsidiary of
CRP that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant
subsidiary, will automatically cause all outstanding Senior Notes to become due and payable.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet
obligations. As of December 31, 2017, we had no off-balance sheet arrangements.
57
Contractual Obligations
The Company routinely enters or extends operating agreements, office and equipment leases, drilling and completion rig
contracts, among others, in the ordinary course of business. The following table summarizes our obligations and commitments as
of December 31, 2017 to make future payments under certain contracts for the time periods specified below.
(in thousands)
Drilling rig commitments (1)
Office leases (2)
Water disposal agreement (3)
Purchase obligations (4)
Asset retirement obligations (5)
Long term debt obligations (6)
Cash interest expense on long-term debt
obligations (7)
Transportation and gathering (8)
2018
2019
2020
2021
2022
Thereafter
Total
$ 19,714
$
1,620
$
— $
— $
— $
— $
21,334
2,360
1,825
4,400
—
—
23,871
2,044
2,322
1,825
13,200
—
—
23,574
2,044
2,163
1,825
8,800
1,072
—
2,073
1,825
—
—
—
274
—
—
—
—
—
—
—
11,089
400,000
9,192
7,300
26,400
12,161
400,000
21,500
21,500
21,500
66,292
178,237
—
—
—
—
4,088
Total
$ 54,214
$
44,585
$
35,360
$
25,398
$ 21,774
$ 477,381
$
658,712
(1)
(2)
The Company has six drilling rigs under long-term contract as of December 31, 2017. Early termination of these contracts would require
termination penalties of $14.7 million to be paid as of December 31, 2017, which would be paid in lieu of paying the remaining drilling
commitments under these contracts.
The Company leases office space in Colorado, Texas and New Mexico.
(3) The Company entered into a water disposal agreement in which we have contracted for transportation and disposal of the produced water
from our operated wells. Under the terms of the agreement, Centennial is obligated to provide a minimum volume of produced water or
else pay for any deficiencies at the price stipulated in the contract. The obligations reported above represent our minimum financial
commitments pursuant to the terms of this contract as of December 31, 2017. Actual expenditures under this contract may exceed the
minimum commitments presented above.
(4)
The Company entered into a supply agreement to purchase frac and sand product for a term of three years. Under the terms of the
agreement, Centennial is obligated to purchase a minimum volume of frac and sand product at a fixed sales price. A prepayment of $13.2
million was made during 2017 and will be used as a partial credit against monthly purchases. The obligations reported above represent our
minimum financial commitments pursuant to the terms of this contract as of December 31, 2017. Actual expenditures under this contract
may exceed the minimum commitments presented above.
(5) Asset retirement obligations reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and
natural gas wells and related restoration in accordance with applicable laws and regulations. Refer to Note 11—Asset Retirement
Obligations in Item 8 of Part II of this Annual Report on Form 10-K for additional information.
(6) Long-term debt consists of the principal amounts of the Senior Notes due 2026. As of December 31, 2017, there was no outstanding
borrowings under the credit facility.
(7) Cash interest expense on the Senior Notes is estimated assuming no principal repayment until the maturity of the instrument. Cash interest
expense on the credit facility assumes no borrowing outstanding and includes the unused commitment fees.
(8)
In June 2017, the Company entered into a transportation service agreement through December 31, 2019 whereby it is required to deliver
40,000 MMBtu per day or pay for any deficiencies at the price stipulated in the contract. This delivery commitment is tied to the
Company’s natural gas production in Reeves and Ward counties, Texas.
Recently Issued Accounting Standards
Please refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies, in Part II, Item 8. Financial
Statements and Supplementary Data in this Annual Report on Form 10-K for a discussion of recently issued accounting standards
and their anticipated effect on our business.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial
statements, which have been prepared in accordance with GAAP. The preparation of these statements requires us to make certain
assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of
contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical
experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to
58
changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other
factors. A summary of our significant accounting policies is detailed in Note 1—Basis of Presentation and Summary of Significant
Accounting Policies, in Part II, Item 8. Financial Statements and Supplementary Data in this Annual Report on Form 10-K.
We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position
and results of operations and which require the application of significant judgment by our management.
Oil and Natural Gas Reserve Quantities
We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method
inherently relies on estimation of proved crude oil, natural gas and NGLs reserves. The amount of estimated proved reserve
affects whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into
net income and presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash
flows to be generated by producing properties are used for evaluating proved properties for impairment and the expected future
taxable income available to realize deferred income tax assets, also in part, rely on estimates of quantities of net reserves. Proved
oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing
economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to
operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic
methods are used for the estimation. Key features of the Company’s reserve estimation process are covered in Preparation of
Reserve Estimates in Item 2.
We engage Netherland, Sewell & Associates, Inc., our independent petroleum engineer, to prepare our total calculated proved
reserve. Estimates prepared by petroleum engineers may be higher or lower than our estimates. Because these estimates depend
on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the
quantities of oil and gas that are ultimately recovered. For example, if the crude oil and natural gas prices used in our year-end
reserve estimates increased or decreased by 10%, our proved reserve quantities at December 31, 2017 would have increased by
1.2 MMBoe (0.63%) or decreased by 1.8 million MMBoe (0.98%), respectively, and the pre-tax PV10% of our proved reserves
would have increased by $325.2 million (18.6%) or decreased by $327.3 million (18.72%), respectively. We continually make
revisions to reserve estimates throughout the year as additional information becomes available. We make changes to depletion
rates and impairment calculations (when impairment indicators arise) in the same period that changes to reserve estimates are
made.
Impairment of Oil and Natural Gas Properties
We assess our proved properties for impairment when events or changes in circumstances indicate that the carrying value of
assets may not be recoverable. For purposes of an impairment evaluation, our proved oil and natural gas properties must be
grouped at the lowest level for which independent cash flows can be identified. If the sum of the undiscounted estimated cash
flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying
value is written down to the estimated fair value. Fair value calculated for the purpose of testing impairment is estimated using the
present value of expected future cash flows method and comparative market prices when appropriate. Fair value estimates are
based on projected financial information which we believe to be reasonably likely to occur. An estimate of the sensitivity to
changes in assumptions in our undiscounted cash flow calculations is not practicable, given the numerous assumptions that can
materially affect our estimates. Unfavorable adjustments to our assumptions would likely be offset by favorable adjustments in
other assumptions. For example, the impact of sustained reduced commodity prices on future undiscounted cash flows would
likely be partially offset by lower costs.
Unproved properties costs consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. We
evaluate significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance,
seismic interpretation or future plans to develop acreage.
Business and Asset Acquisitions
For business and asset acquisitions, we generally recognize the identifiable assets acquired, the liabilities assumed and any
noncontrolling interest in the acquiree at their estimated fair values on the acquisition date. Determining fair value requires
management’s judgment and involves the use of significant estimates and assumptions with respect to projections of future
production volumes, pricing and cash flows, benchmark analysis of comparable public companies, discount rates, expectations
regarding customer contracts and relationships, and other management estimates. The judgments made in the determination of the
estimated fair value assigned to the assets acquired, liabilities assumed and any noncontrolling interest in the investee, as well as
the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods
after acquisition. See Note 2—Business Combination and Note 3—Property Acquisitions in Item 8 of Part II of this Annual Report
on Form 10-K.
59
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described
below. The primary objective of the following information is to provide quantitative and qualitative information about our
potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural
gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators
of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative
trading.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLs production. Pricing for oil,
natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future.
Due to this volatility, we have historically used, and we expect to continue to selectively use, commodity derivative
instruments, such as collars, swaps and basis swaps, to mitigate price risk associated with a portion of our anticipated production.
Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from
operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for our drilling program
and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas
prices and may partially limit our potential gains from future increases in prices. Our credit agreement limits our ability to enter
into commodity hedges covering greater than 80% of our reasonably anticipated projected production volume.
The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in
place as of December 31, 2017:
Description & Production Period
Crude Oil Basis Swaps:
January 2018 - June 2018
January 2018 - June 2018
January 2018 - June 2018
January 2018 - June 2018
January 2018 - June 2018
January 2018 - December 2018
January 2018 - December 2018
January 2018 - December 2018
January 2018 - December 2018
January 2018 - December 2018
Weighted
Average
Differential
($/Bbl) (1)
0.10
0.20
0.20
0.22
0.17
0.00
0.00
0.00
0.00
0.00
Volume (Bbl)
181,000
$
181,000
181,000
181,000
181,000
182,500
182,500
730,000
365,000
365,000
(1) The oil basis swap transactions are settled based on the difference between the arithmetic average of the ARGUS MIDLAND WTI and
ARGUS WTI CUSHING settlements, during the relevant calculation period.
Description & Production Period
Natural Gas Basis Swaps:
January 2018 - December 2018
January 2019 - December 2019
Volume (MMBtu)
Weighted Average
Differential
($/MMBtu) (1)
1,825,000
1,825,000
$
$
(0.43)
(0.43)
(1)
The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and
the NYMEX price of Natural Gas during the relevant calculation period.
The fair value of these commodity derivative instruments at December 31, 2017 was a net asset of $0.9 million. A
hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of December 31, 2017
would cause less than a $0.1 million increase or decrease in this fair value liability, and a hypothetical upward or downward shift
of 10% per Mcf in the NYMEX forward curve for natural gas as of December 31, 2017 would cause a $0.2 million increase or
decrease, respectively, in this fair value liability.
60
Interest Rate Risk
The Company’s ability to borrow and the rates offered by lenders can be adversely affected by credit market and the
Company’s credit rating. CRP’s credit facility interest rate is based on a LIBOR spread, which expose the Company to interest
rate risk if we have borrowings outstanding. At December 31, 2017, the Company had no borrowings outstanding under its credit
facility. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest
rates applicable to our outstanding indebtedness.
The remaining $391 million of the Company’s long-term debt is a senior note with a fixed interest rate; therefore, it is not
affected by interest rate movements. For additional information regarding the Company’s debt instruments, see Note 5—Long-
Term Debt, in Item 8 of Part II of this Annual Report on Form 10-K.
61
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CENTENNIAL RESOURCE DEVELOPMENT, INC.
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reports of Independent Registered Public Accounting Firms
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Cash Flows
Consolidated Statements of Owners’ Equity and Consolidated Statements of Shareholders’ Equity
Notes to Consolidated Financial Statements
Note 1—Basis of Presentation and Summary of Significant Accounting Policies
Note 2—Business Combination
Note 3—Property Acquisitions
Note 4—Accounts Receivable, Accounts Payable and Accrued Expenses
Note 5—Long-Term Debt
Note 6—Income Taxes
Note 7—Shareholders’ Equity and Noncontrolling Interest
Note 8—Stock-Based Compensation
Note 9—Derivative Instruments
Note 10—Fair Value Measurements
Note 11—Asset Retirement Obligations
Note 12—Transactions with Related Parties
Note 13—Commitments and Contingencies
Note 14—Subsequent events
Supplemental Information to Consolidated Financial Statements
Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited)
Selected Quarterly Financial Data (Unaudited)
Page
63
65
66
67
69
71
71
77
79
80
81
82
84
86
89
91
92
92
94
95
96
100
62
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Centennial Resource Development, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Centennial Resource Development, Inc. and subsidiaries (the
Company) as of December 31, 2017 and 2016, the related consolidated statements of operations, shareholders’ (owners’) equity
and cash flows for the year ended December 31, 2017 and the period October 11, 2016 through December 31, 2016 (Successor
Company operations), and the period from January 1, 2016 to October 10, 2016 and for the year ended December 31, 2015
(Predecessor Company operations), and the related notes (collectively, the consolidated financial statements). In our opinion, the
consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31,
2017 and 2016, the results of its operations and its cash flows for the year ended December 31, 2017 and the period October 11,
2016 through December 31, 2016 (Successor Company operations) and for the period from January 1, 2016 to October 10, 2016
and the year ended December 31, 2015 (Predecessor Company operations), in conformity with U.S. generally accepted
accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated February 26, 2018 expressed an unqualified opinion on the effectiveness of the Company’s
internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and
the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as
well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a
reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2014.
Denver, Colorado
February 26, 2018
63
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Centennial Resource Development, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Centennial Resource Development, Inc. and subsidiaries’ (the Company) internal control over financial reporting
as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal
Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets of Centennial Resource Development, Inc. and subsidiaries (the Company) as of
December 31, 2017 and 2016, the related consolidated statements of operations, shareholders’ (owners’) equity and cash flows for
the year ended December 31, 2017 and the period October 11, 2016 through December 31, 2016 (Successor Company
operations), and the period from January 1, 2016 to October 10, 2016 and for the year ended December 31, 2015 (Predecessor
Company operations), and the related notes (collectively, the consolidated financial statements), and our report dated February 26,
2018 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual
Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal
control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required
to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of
the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Denver, Colorado
February 26, 2018
64
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except share amounts)
December 31, 2017
December 31, 2016
ASSETS
Current assets
Cash and cash equivalents
Accounts receivable, net
Derivative instruments, net
Prepaid and other current assets
Total current assets
Oil and natural gas properties, successful efforts method
Unproved properties
Proved properties
Accumulated depreciation, depletion and amortization
Total oil and natural gas properties, net
Other property and equipment, net
Total property and equipment, net
Noncurrent assets
Derivative instruments, net
Other noncurrent assets
Total assets
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued expenses
Derivative instruments, net
Total current liabilities
Noncurrent liabilities
Long-term debt, net
Asset retirement obligations
Deferred tax liability, net
Derivative instruments, net
Total liabilities
Commitments and contingencies (Note 13)
Shareholders’ Equity
Preferred stock, $.0001 par value, 1,000,000 shares authorized:
Series A: 1 share issued and outstanding
Series B: no shares issued and outstanding at December 31, 2017 and 104,400 shares
issued and outstanding at December 31, 2016
Common stock, $0.0001 par value, 620,000,000 shares authorized:
Class A: 261,337,636 shares issued and 260,327,920 shares outstanding at December 31,
2017 and 201,091,646 shares issued and 200,835,049 shares outstanding at December
31, 2016
Class C (Convertible): 15,661,338 shares issued and outstanding at December 31, 2017
and 19,155,921 shares issued and outstanding at December 31, 2016
Additional paid-in capital
Retained earnings (accumulated deficit)
Total shareholders’ equity
Noncontrolling interest
Total equity
Total liabilities and shareholders’ equity
$
$
$
$
117,315
78,786
433
6,051
202,585
1,952,680
1,602,002
(173,906)
3,380,776
5,465
3,386,241
662
27,081
3,616,569
199,533
240
199,773
390,764
12,161
9,899
—
612,597
—
—
26
2
2,767,558
66,639
2,834,225
169,747
3,003,972
3,616,569
$
$
$
$
134,083
14,734
431
2,078
151,326
1,905,661
604,022
(14,436)
2,495,247
2,193
2,497,440
—
2,876
2,651,642
86,100
5,361
91,461
—
7,226
—
20
98,707
—
—
20
2
2,364,049
(8,929)
2,355,142
197,793
2,552,935
2,651,642
The accompanying notes are an integral part of these consolidated financial statements.
65
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Net revenues
Oil sales
Natural gas sales
NGL sales
Total net revenues
Operating expenses
Lease operating expenses
Severance and ad valorem taxes
Gathering, processing and transportation expenses
Depreciation, depletion and amortization
Impairment and abandonment expenses
Exploration expense
Contract termination and rig stacking
General and administrative expenses
Incentive unit compensation
Total operating expenses
Total operating income (loss)
Other income (expense)
Gain (loss) on sale of oil and natural gas properties
Interest expense
Net gain (loss) on derivative instruments
Other income
Other income (expense)
Income (loss) before income taxes
Income tax (expense) benefit
Net income (loss)
Less: Net income (loss) attributable to noncontrolling interest
Net income (loss) attributable to common shareholders
Income (loss) per share:
Basic
Diluted
$
$
$
Successor
Predecessor
Year Ended
December 31,
2017
October 11,
2016
through
December 31,
2016
January 1,
2016
through
October 10,
2016
Year Ended
December 31,
2015
$
336,931
$
24,313
$
59,787
$
77,643
48,868
44,103
429,902
41,336
23,173
34,259
161,628
(29)
14,373
—
49,882
—
324,622
105,280
8,796
(5,729)
5,138
—
8,205
113,485
(29,930)
83,555
7,987
75,568
0.32
0.32
$
$
$
3,449
1,955
29,717
3,541
1,636
2,187
14,877
—
1,468
—
13,091
—
36,800
(7,083)
24
(378)
(1,548)
—
(1,902)
(8,985)
—
(8,985)
(904)
6,045
3,284
69,116
11,036
3,696
4,583
62,964
2,545
920
—
24,661
165,394
275,799
(206,683)
11
(5,626)
(6,838)
6
(12,447)
(219,130)
406
7,965
4,852
90,460
21,173
5,021
5,732
90,084
7,619
84
2,387
14,206
—
146,306
(55,846)
2,439
(6,266)
20,756
20
16,949
(38,897)
572
(218,724)
(38,325)
—
—
(8,081)
$
(218,724)
$
(38,325)
(0.05)
(0.05)
The accompanying notes are an integral part of these consolidated financial statements.
66
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Depreciation, depletion and amortization
Incentive unit compensation
Stock-based compensation expense
Noncash transaction cost
Impairment and abandonment expenses
Exploratory dry hole costs
Write-off of deferred S-1 related expense
Deferred tax expense (benefit)
(Gain) loss on sale of oil and natural gas properties
Non-cash portion of derivative (gain) loss
Amortization of debt issuance costs
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable
Increase in prepaid and other assets
Increase (decrease) in accounts payable and other liabilities
Net cash provided by operating activities
Cash flows from investing activities
Proceeds withdrawn from trust account
Acquisition of Centennial Resource Production, LLC
Acquisition of oil and natural gas properties
Drilling and development capital expenditures
Purchases of other property and equipment
Other assets
Proceeds from sales of oil and natural gas properties
Net cash used by investing activities
Cash flows from financing activities
Issuance of Class A common shares
Issuance of Preferred Series B Shares
Underwriting discount and offering costs
Payment of deferred underwriting compensation
Proceeds from revolving credit facility
Repayment of revolving credit facility
Proceeds from senior notes
Proceeds from stock options exercised
Restricted stock used for tax withholdings
Capital contributions
Debt issuance costs
Financing obligation
Net cash provided by financing activities
Net increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash, beginning of period
Successor
Predecessor
Year Ended
December 31,
2017
October 11,
2016
through
December 31,
2016
January 1,
2016
through
October 10,
2016
Year ended
December 31,
2015
$
83,555
$
(8,985)
$
(218,724) $
(38,325)
161,628
—
13,759
—
(29)
5,658
—
29,930
(8,796)
(5,805)
887
(43,553)
(4,088)
26,772
259,918
—
—
(435,547)
(566,427)
(4,921)
(7,907)
22,496
(992,306)
340,750
—
(7,291)
—
275,000
(275,000)
400,000
877
(644)
—
(9,472)
—
724,220
(8,168)
134,083
14,877
—
1,333
—
—
—
—
—
(24)
2,602
70
(983)
(1,092)
1,612
9,410
500,561
(1,375,744)
(849,642)
(24,107)
(801)
—
—
(1,749,733)
1,540,556
379,494
(27,104)
(17,500)
—
—
—
—
—
—
(1,115)
(63)
1,874,268
133,945
138
62,964
165,394
—
14,049
2,545
—
—
(406)
(11)
23,461
376
969
(170)
1,293
51,740
—
—
(55,564)
(45,605)
(265)
—
—
(101,434)
—
—
—
—
55,000
(5,000)
—
—
—
—
—
(2,074)
47,926
(1,768)
1,768
90,084
—
—
—
7,619
—
1,585
(572)
(2,439)
14,737
482
5,244
(864)
(8,669)
68,882
—
—
(43,223)
(156,006)
(2,097)
—
2,691
(198,635)
—
—
—
—
92,000
(83,000)
—
—
—
111,396
(259)
(1,633)
118,504
(11,249)
13,017
Cash, cash equivalents and restricted cash, end of period
$
125,915
$
134,083
$
— $
1,768
The accompanying notes are an integral part of these consolidated financial statements.
67
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(in thousands)
Supplemental cash flow information and noncash activity:
Supplemental cash flow information
Cash paid for interest
Supplemental noncash activity
Accrued capital expenditures included in accounts payable and
accrued expenses
Asset retirement obligations incurred, including changes in
estimate
Financing obligation
Successor
Predecessor
Year Ended
December 31,
2017
October 11,
2016
through
December 31,
2016
January 1,
2016
through
October 10,
2016
Year ended
December 31,
2015
$
$
4,280
$
234
126,480
$
65,217
$
$
5,092
$
5,782
21,025
$
13,124
4,044
—
186
—
206
—
146
3,770
Reconciliation of cash, cash equivalents and restricted cash presented on the Consolidated Statements of Cash Flows:
Cash and cash equivalents
Restricted cash (1)
Total cash, cash and cash equivalents and restricted cash
$
$
117,315
8,600
125,915
$
$
134,083
—
134,083
—
—
—
Year Ended
December 31,
2017
October 11,
2016
through
December 31,
2016
January 1,
2016
through
October 10,
2016
Year ended
December 31,
2015
1,768
—
1,768
(Successor)
(Predecessor)
(1) Included in Other Noncurrent Assets line item on the Consolidated Balance Sheets
The accompanying notes are an integral part of these consolidated financial statements.
68
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Successor)
(in thousands)
Common Stock
Preferred Stock
Class A
Class B
Class C
Series A
Series B
Shares Amount Shares Amount Shares Amount
Shares
Amount Shares Amount
Additional
Paid-In
Capital
Retained
Earnings
(Accumulated
Deficit)
Total
Shareholder's
Equity
Non-
controlling
Interest
Total
Equity
Balance at October 10, 2016
2,175
$ — 12,500
$
1
— $ —
— $ —
— $ — $
5,460
$
(461)
$
5,000
$
— $
5,000
— $ — 19,156
$
2
— $ —
— $ — $ 1,494,826
$
(848)
$ 1,493,996
$ 176,981
$ 1,670,977
Conversion of common shares from
Class B to Class A at transaction
Class A common shares released
from possible redemption
Class C common shares issued
Conversion of common shares from
Class C to Class A
Sale of unregistered Class A
common shares
Underwriters’ discount and
offering expense
Net loss
Noncontrolling interest in Centennial
Resource Production, LLC
12,500
47,825
—
844
101,005
—
—
—
Balance at October 11, 2016
164,349
$
Restricted stock issued
Sale of unregistered Class A
common shares
Sale of unregistered Class B
preferred shares
Underwriters’ discount and
offering expense
Change in equity due to issuance
of shares by Centennial Resource
Production, LLC
Stock-based compensation
Net loss
257
36,486
—
—
—
—
—
Balance at December 31, 2016
201,092
$
Warrants exercised
Restricted stock issued
Restricted stock forfeited
Restricted stock used for
tax withholding
Option Exercises
derreferp B seireS fo noisrevnoC
shares to Class A common shares
Sale of unregistered Class A
common shares
Underwriters' discount and
offering expense
Stock-based compensation
Change in equity due to issuance
of shares by Centennial Resource
Production, LLC
Conversion of common
shares from Class C to
Class A, net of tax
Net income
6,236
902
(12)
(33)
58
26,100
23,500
—
—
—
3,495
—
Balance at December 31, 2017
261,338
$
1
5
—
—
10
—
—
—
16
—
4
—
—
—
—
—
20
1
—
—
—
—
3
2
—
—
—
—
—
26
(1)
—
—
——
— 20,000
(844)
——
—
2
—
(12,500)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $ — 19,156
$
—
—
——
——
——
——
—
—
——
—
—
——
—
——
——
—
——
—
2
—
—
—
——
——
—
—
——
——
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— (3,495)
—
—
——
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
478,243
(2)
7,798
1,010,040
(6,713)
—
—
—
—
—
—
—
—
—
478,248
—
—
—
—
7,798
(7,798)
1,010,050
(6,713)
(387)
(387)
—
—
—
—
478,248
—
—
1,010,050
(6,713)
(387)
—
—
184,779
184,779
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
104
—
—
—
—
—
—
—
—
—
—
—
—
530,503
379,494
(20,391)
(21,716)
1,333
—
—
—
—
—
—
—
(8,081)
—
530,507
379,494
(20,391)
—
—
—
—
—
530,507
379,494
(20,391)
(21,716)
21,716
—
1,333
(8,081)
—
(904)
1,333
(8,985)
— $ —
104
$ — $ 2,364,049
$
(8,929)
$ 2,355,142
$ 197,793
$ 2,552,935
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— (104)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1)
—
—
(644)
877
(3)
340,748
(7,291)
13,759
(2,682)
58,746
—
—
—
—
—
—
—
—
—
—
—
—
(644)
877
—
340,750
(7,291)
13,759
—
—
—
—
—
—
—
—
—
—
—
(644)
877
—
340,750
(7,291)
13,759
(2,682)
2,682
—
58,746
(38,715)
20,031
—
75,568
75,568
7,987
83,555
— $ — 15,661
$
2
— $ —
— $ — $ 2,767,558
$
66,639
$ 2,834,225
$ 169,747
$ 3,003,972
The accompanying notes are an integral part of these consolidated financial statements.
69
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF OWNERS’ EQUITY (Predecessor)
(in thousands)
Balance at December 31, 2014
Contributions
Deemed distribution from sale of assets
Net loss
Balance at December 31, 2015
Contributions
Net loss
Balance at October 10, 2016
The accompanying notes are an integral part of these consolidated financial statements.
Total equity
377,932
111,396
(139)
(38,325)
450,864
179,442
(218,724)
411,582
$
70
Note 1—Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Centennial Resource Development, Inc. (the “Company” or “Centennial”) is 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. The
Company’s assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, and its properties consist of large,
contiguous acreage blocks primarily in Reeves County in West Texas and Lea County in New Mexico.
Centennial was originally incorporated in Delaware on November 4, 2015 as a special purpose acquisition company under
the name Silver Run Acquisition Corporation (“Silver Run”) for the purpose of effecting a merger, capital stock exchange, asset
acquisition, stock purchase, reorganization or similar business combination involving the Company and one or more businesses.
On February 29, 2016, the Company consummated its 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, the Company 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”). In connection with the closing of the Business
Combination, the Company changed its name from “Silver Run Acquisition Corporation” to “Centennial Resource Development,
Inc.” Refer to Note 2—Business Combination for further information related to 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 located primarily
in the Permian Basin of West Texas. Until the closing of the Business Combination, CRP operated as a privately-held independent
oil and natural gas company.
Principles of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of the Company and its majority owned subsidiary CRP, and
CRP’s wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the
United States of America (“GAAP”) and the rules and regulations of the Securities and Exchange Commission (“SEC”). All
intercompany balances and transactions have been eliminated in consolidation.
Noncontrolling interests represent third-party ownership in the Company’s consolidated subsidiary and is presented as a
component of equity. See Note 7—Shareholders' Equity and Noncontrolling Interest for further discussion of noncontrolling
interest.
Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying consolidated
financial statements. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
As a result of the Business Combination, the Company is the acquirer for accounting purposes, and CRP is the acquiree and
accounting Predecessor. The Company’s financial statement presentation distinguishes CRP as an accounting “Predecessor” for
periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, which
includes consolidation of CRP subsequent to the Business Combination on October 11, 2016. The Business Combination was
accounted for as a business combination using the acquisition method of accounting, and the Successor financial statements
reflect a new basis of accounting that is based on the fair value of CRP’s net assets acquired. Refer to Note 2—Business
Combination for further information related to the Business Combination. As a result of the application of the acquisition method
of accounting as of the Business Combination, the financial statements for the Predecessor periods and for the Successor periods
are presented on a different basis of accounting.
Use of Estimates
The preparation of the Company’s consolidated financial statements requires the Company’s management to make various
assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the
disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of
the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously
established.
The more significant areas requiring the use of assumptions, judgments and estimates include: (i) oil and natural gas reserves;
(ii) cash flow estimates used in impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset
retirement obligations; (v) determining fair value and allocating purchase price in connection with business combinations and
asset acquisitions; (vi) accrued revenue and related receivables; and (vii) accrued liabilities.
71
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Risks and Uncertainties
The prices received for oil, natural gas and NGLs production heavily influences the Company’s 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
can be volatile in response to changes in global and domestic supply and demand and market uncertainty. The Company generally
funds its operations and capital expenditures with cash flow from its operations, borrowings under CRP’s revolving credit facility
and offerings of debt and equity securities. The Company expects to be able to fund its operations, planned capital expenditures
and working capital requirements during the next 12 months and the foreseeable future. However, continued volatility of oil and
gas prices could have an adverse effect on the Company’s future business, financial condition, results of operations, operating
cash flows, liquidity and quantities of oil and gas reserves that may be economically produced, which could impact the
Company’s ability to comply with the financial covenants under CRP’s credit facility and limit further borrowings to fund capital
expenditures and potential acquisitions. Additionally, if forward prices decline, the Company could incur additional impairment of
its oil and gas assets.
Cash and Cash Equivalents and Restricted Cash
The Company considers all highly liquid instruments with an original maturity of three months or less at the time of issuance
to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short-term maturity
of these investments. From time to time, the Company is required to maintain cash in separate accounts, the use of which, is
restricted by the terms of contracted arrangements. Such amounts are included in Other Noncurrent Assets on the Consolidated
Balance Sheets.
Accounts Receivable
Accounts receivable consists mainly of receivables from oil and natural gas purchasers and from joint interest owners on
properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold
future revenue disbursements to recover non-payment of joint interest billings. Accordingly, oil and natural gas receivables are
collected, and the Company has minimal bad debts.
Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual
company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. The Company
establishes an allowance for doubtful accounts equal to the estimable portions of accounts receivable for which failure to collect is
probable. The Company had no allowance for doubtful accounts as of December 31, 2017 and December 31, 2016.
Credit Risk and Other Concentrations
The Company normally sells production to a relatively small number of customers, as is customary in its business. The table
below presents percentages by purchaser that accounted for 10% or more of our total oil, natural gas and NGL sales for each year
as presented:
Year Ended December 31, 2017
Shell Trading (US) Company
BP America
Eagleclaw Midstream Ventures, LLC
Year Ended December 31, 2016
Plains Marketing, LP
Shell Trading (US) Company
Permian Transport and Trading
Year Ended December 31, 2015
Plains Marketing, LP
33%
16%
14%
48%
22%
11%
64%
During these periods, no other purchaser accounted for 10% or more of our revenue. The loss of any of the Company’s major
purchasers could materially and adversely affect its revenues in the short-term. However, based on the current demand for oil and
natural gas and the availability of other purchasers, the Company believes that the loss of any major purchaser would not have a
material adverse effect on its financial condition and results of operations because crude oil and natural gas are fungible products
with well-established markets and numerous purchasers.
72
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes
itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative
contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk.
The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; and
(ii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis.
Oil and Natural Gas Properties
The Company’s oil and natural gas producing activities are accounted for using the successful efforts method of accounting.
Under the successful efforts method, the costs incurred to acquire, drill, and complete productive development wells are
capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs,
geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions
are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the
well is determined to be unsuccessful. Costs to operate and maintain wells and field equipment are expensed as incurred.
The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not
subject to current amortization. Interest is capitalized only for the period that activities are in process to bring the projects to their
intended use. Capitalized interest cannot exceed interest expense for the period capitalized. The Company capitalized interest of
$1.2 million during the year ended December 31, 2017. The Company did not have any capitalized interest for the periods
October 11, 2016 through December 31, 2016 (Successor) and January 1, 2016 through October 10, 2016 (Predecessor) and for
the year ended December 31, 2015 (Predecessor).
Proved Oil and Natural Gas Properties. Costs incurred to obtain access to proved reserves and to provide facilities for
extracting, treating, gathering and storing oil, natural gas and NGLs are capitalized. All costs incurred to drill and equip successful
exploratory wells, development wells, development-type stratigraphic test wells and service wells, including unsuccessful
development wells, are capitalized. Capitalized costs are depleted on a unit-of production method based on proved oil and gas
reserves.
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property
are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly
affects the unit-of-production amortization rate, in which case a gain or loss is recognized. Gains or losses from the disposal of
complete units of depreciable property are recognized to income.
The Company reviews it proved oil and natural gas properties for impairment when events and circumstances indicate a
possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash
flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and
natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated
undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to fair
value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices,
future production estimates, estimated future capital expenditures and discount rates commensurate with the risk associated with
realizing the projected cash flows. There were no impairments of proved oil and natural gas properties for the year ended
December 31, 2017 (Successor), for the periods October 11, 2016 through December 31, 2016 (Successor) and January 1, 2016
through October 10, 2016 (Predecessor) and for the year ended December 31, 2015 (Predecessor).
Unproved Properties. Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved
reserves. Acquisition costs associated with the acquisition of non-producing leaseholds are recorded as unproved leasehold costs
and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in
addition to options to lease, broker fees, recording fees and other similar costs related to acquiring properties. Leasehold costs are
classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural
gas properties. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on or
otherwise attributed to the property.
The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results,
reservoir performance, seismic interpretation or future plans to develop acreage. There was no unproved property impairment
expense for the year ended December 31, 2017 (Successor) or for the period from October 11, 2016 through December 31, 2016
(Successor). For the period from January 1, 2016, through October 10, 2016 (Predecessor), the Predecessor recorded unproved
property impairment expense of $2.5 million for leases which have expired, or were expected to expire. For the year ended
December 31, 2015 (Predecessor), the Predecessor recorded unproved property impairment expense of $7.6 million for leases
which have expired, or were expected to expire.
73
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Other Property and Equipment
Other property and equipment such as office furniture and equipment, buildings, vehicles, and computer hardware and
software is recorded at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets
ranging from three to twenty years. Major renewals and improvements are capitalized while expenditures for maintenance and
repairs are expensed as incurred. When other property and equipment is sold or retired, the capitalized costs and related
accumulated depreciation are removed from the accounts.
Deferred Loan Costs
Deferred loan costs related to the Company’s revolving credit facility are included in the line item Other Noncurrent Assets
on the Consolidated Balance Sheets and are stated at cost, net of amortization. These costs are amortized to interest expense on a
straight-line basis over the borrowing term. Costs incurred in connection with the 5.375% Senior Notes Offering are also deferred
and charged to interest expense over the term of the agreement; however, these amounts are reflected as a reduction of the related
obligation in the line item Long-term Debt on the Consolidated Balance Sheets.
Derivative Financial Instruments
In order to manage its exposure to oil and natural gas price volatility, the Company opportunistically utilizes derivative
transactions from time to time, including commodity swap, basis swap, collar, and other similar agreements. To the extent legal
right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has
exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The Company actively monitors
the creditworthiness of counterparties and assesses the impact, if any, on its derivative position.
The Company records derivative instruments on the Consolidated Balance Sheets as either an asset or liability measured at
fair value and records changes in the fair value of derivatives in current earnings as they occur. The Company’s derivatives have
not been designated as hedges for accounting purposes. For additional discussion on derivatives, please refer to Note 9—
Derivative Instruments.
Asset Retirement Obligations
The Company recognizes an estimated liability for future costs associated with abandonment of its oil and natural gas
properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the
related long-lived asset are recorded at the time a well is drilled or acquired. The fair value of the liability recognized is based on
the present value of the estimated future cash outflows associated with its plug and abandonment obligations. The Company
depletes the amount added to proved oil and natural gas property costs and recognizes expense in connection with the accretion of
the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties. Revisions
typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new
requirements regarding the abandonment of wells. For additional discussion, please refer to Note 11—Asset Retirement
Obligations.
Revenue Recognition
The Company derives revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when
the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date
of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end
of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will
receive. The Company follows the sales method of accounting for its oil and natural gas revenue, whereby revenue is recorded
based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume
produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property
greater than the expected remaining proved reserves. The Company had no significant imbalances as of December 31, 2017 or
2016.
Income Taxes
Income taxes and uncertain tax positions are accounted for in accordance with Financial Accounting Standards Board
(“FASB”) Accounting Standards Codification (“ASC”) 740, Accounting for Income Taxes (“ASC 740”). Deferred income taxes
are provided for the differences between the bases of assets and liabilities for financial reporting and income tax purposes. Tax
positions meeting the more-likely-than-not recognition threshold are measured pursuant to the guidance set forth in ASC 740. We
routinely assess the realizability of deferred income tax assets based on several factors and a valuation allowance is established if
it’s more likely that not that some portion or all of deferred income tax assets will not be realized.
74
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Stock-Based Compensation (Successor)
The Company grants various types of stock-based awards including stock options, restricted stock awards and performance
stock units. The Company recognizes compensation related to all stock-based awards in the financial statements based on their
estimated grant-date fair value and is recognized ratably over the applicable vesting period. The fair value of stock option awards
is determined using the Black-Scholes option pricing model. Stock options typically expire ten years from the grant date and have
service-based vesting schedules of three years. Service-based restricted stock awards are valued using the market price of the
Company’s common stock on the grant date and generally vest ratably over a three-year service period. Performance stock units
are subject to market-based vesting criteria as well as a three-year service period and the grant-date fair value is estimated using a
Monte Carlo valuation model. See Note 8—Stock-Based Compensation for additional information regarding the Company’s stock-
based compensation.
Incentive Unit Compensation (Predecessor)
Pursuant to the LLC Agreement of CRP (prior to the Business Combination), certain incentive units were available to be
issued to the Company’s management and employees, consisting of Tier I, Tier I A, Tier II, Tier III and Tier IV units. The
incentive units were intended to be compensation for services rendered to CRP. Tier Incentive units are accounted for as liability
awards under FASB ASC Topic 718, Compensation: Stock Compensation (“ASC 718”), with compensation expense based on
period-end fair value. Refer to Note 8—Stock-Based Compensation for additional information regarding the CRP’s incentive unit
compensation (Predecessor).
Earnings (Loss) Per Share
The two-class method of computing earnings per share is required for entities that have participating securities. The two-class
method is an earnings allocation formula that determines earnings per share for participating securities according to dividends
declared (or accumulated) and participation rights in undistributed earnings.
Basic earnings per share (“EPS”) is calculated by dividing net income available to common shareholders by the weighted
average shares outstanding during each period. Dilutive EPS is calculated by dividing adjusted net income available to common
shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially
dilutive securities. Potentially dilutive securities for the diluted EPS calculation consists of (i) unvested restricted stock and
performance stock units, outstanding stock options and warrants using the treasury stock method, and (ii) the Company’s Class C
common stock using the “if-converted” method, which is net of tax.
75
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Shares of the Company’s unvested restricted stock and performance stock units are eligible to receive dividends; however,
dividend rights will be forfeited if the award does not vest. Accordingly, these shares are not considered participating securities.
Shares of the Company’s Class C Common Stock and warrants do not share in earnings or losses and are therefore not
participating securities as well. In addition, the Company’s shares of Series B Preferred Stock were converted into shares of Class
A Common Stock on May 25, 2017 as a result of shareholder vote. As such, the Company no longer has any participating
securities as of December 31, 2017.
The following table reflects the allocation of net income to common stockholders and EPS computations for the periods
indicated based on a weighted average number of common stock outstanding for the period:
(in thousands, except per share data)
Net income (loss) attributable to common shareholders
Add: Income from conversion of Class C Common Stock
Less: Loss allocable to participating securities
Adjusted net income (loss) attributable to common shareholders
Basic net earnings (loss) per share
Diluted net earnings (loss) per share
Basic weighted average share outstanding
Add: Dilutive effect of potential common shares
Diluted weighted average shares outstanding
Successor
Year Ended
December 31, 2017
October 11, 2016
through
December 31, 2016
$
$
$
$
75,568
$
(8,081)
$
$
$
—
—
75,568
0.32
0.32
235,447
4,307
239,754
—
(46)
(8,035)
(0.05)
(0.05)
165,684
—
165,684
For the year ended December 31, 2017, the diluted earnings per share calculation excludes 0.8 million stock options that were
out-of-the-money and 18.6 million weighted average Class C Common Stock as their effect was anti-dilutive. For the period from
October 11, 2016, through December 31, 2016, the diluted earnings per share calculation excludes all outstanding restricted stock
and options as the Company recognized a net loss and their effect would have been anti-dilutive.
Segment Reporting
The Company operates in only one industry segment which is the exploration and production of oil and natural gas. All of its
operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the
United States.
Recently Issued Accounting Standards
In January 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805):
Clarifying the Definition of a Business. This update affects all reporting entities and the objective of the guidance is to assist with
evaluation of whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The mandatory
effective date for this update is for financial statements issued for fiscal years beginning after December 15, 2017, including
interim periods within those fiscal years. The amendments should be applied prospectively on or after the effective date and
disclosures are not required at transition. Early adoption is permitted for transactions for which the acquisition date occurs before
the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that
have been issued or made available for issuance. The Company early adopted ASU 2017-01 in the second quarter of 2017. Refer
to Note 3—Property Acquisitions for details of the GMT Acquisition.
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash. This update applies to all
entities that are required to present a statement of cash flows. This update expands the statement of cash flows to explain changes
in restricted cash as well cash and cash equivalents. This update will be effective for financial statements issued for fiscal years
beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. This update
should be applied using the retrospective transition method. The Company early adopted ASU 2016-18 in the fourth quarter of
2017 and the only impact was related to presentation. Refer to the Consolidated Statements of Cash Flows for presentation.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash
Payments. This update applies to all entities that are required to present a statement of cash flows. This update provides guidance
on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or
76
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing,
contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds
from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions
received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows
and application of the predominance principle. This update will be effective for financial statements issued for fiscal years
beginning after December 31, 2017, including interim periods within those fiscal years with early adoption permitted. This update
should be applied using the retrospective transition method. Adoption of this standard will only affect the presentation of the
Company’s statements of cash flows and will not have a material impact on its consolidated financial statements.
In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation. This update applies to all entities that
issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including
the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash
flows. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including
interim periods within those fiscal years with early adoption permitted. The Company elected to early adopt this guidance in
October 2016 in conjunction with the issuance of its equity awards.
In February 2016, the FASB issued ASU 2016-02, Leases, which created Topic ASC 842, Leases (“Topic ASC 842”),
superseding current lease requirements under Topic ASC 840. Subsequently, in January 2018, the FASB issued ASU 2018-01,
which provides a practical expedient to the evaluation of existing land easement agreements under ASU 2016-02. ASU 2016-02
and its amendments applies to any entity that enters into a lease, with some specified scope exemptions. Under Topic ASC 842, a
lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-
use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor
accounting, changes were made to align key aspects with the revenue recognition guidance. Topic ASC 842 will be effective for
public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early
adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented
using a modified retrospective approach. Although the Company is still in the process of evaluating the effect of adopting ASU
2016-02 and related amendments, the adoption is expected to result in the recognition of assets and liabilities on its Consolidated
Balance Sheet for current operating leases. The Company is evaluating existing arrangements to determine if they qualify for
lease accounting under Topic ASC 842.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue
recognition requirements in ASC Topic 605, Revenue Recognition, and most industry-specific guidance. The FASB subsequently
issued various ASUs which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU
2014-09 and its amendments provides companies with a single model for use in accounting for revenue arising from contracts
with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core
principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to
recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. In addition, new
qualitative and quantitative disclosure requirements aim to enable financial statement users to understand the nature, amount,
timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 and its amendments are
effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standards permit
retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or
(ii) recognition of a cumulative-effect adjustment as of the date of initial application.
The Company has selected the modified retrospective method and has adopted this guidance as of January 1, 2018, the
effective date. The Company has substantially completed its review of the impact of the new standard on its significant contracts.
However, the Company will finalize the adoption of ASU No. 2014-09 during the first quarter of 2018, but at this time,
management does not believe there will be a material impact to net income or cash flows upon adoption of the new standard.
Where the Company delivers raw gas to midstream processing companies and retains control of its natural gas and plant products
until tailgate of the plant, the cost of such processing will continue to be reflected in the Company’s gathering, processing and
transportation expenses as has been our practice historically. The Company has evaluated the expected disclosure requirements,
changes to relevant business practices, accounting policies and control activities as a result of the adoption of the ASU and does
not expect a material quantitative impact to the Company's consolidated financial statements, other than additional disclosures.
Additionally, the Company will account for any gas imbalances based on the entitlement method rather than the sales method.
This change will not have impact on the Company’s results of operations or financial position in 2018.
Note 2—Business Combination
On October 11, 2016 (the “Closing Date”), the Company consummated the acquisition of approximately 89% of the
outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company (“CRP”),
77
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
pursuant to (i) that certain Contribution Agreement, dated as of July 6, 2016 (as amended by Amendment No. 1 thereto, dated as
of July 29, 2016, the “Contribution Agreement”), among Centennial Resource Development, LLC, a Delaware limited liability
company (“CRP”), NGP Centennial Follow-On LLC, a Delaware limited liability company (“NGP Follow-On”), Celero Energy
Company, LP, a Delaware limited partnership (together with CRD and NGP Follow-On, the “Centennial Contributors”), CRP and
New Centennial, LLC, a Delaware limited liability company (“NewCo”), (ii) that certain Assignment Agreement, dated as of
October 7, 2016, between NewCo and the Company and (iii) that certain Joinder Agreement, dated as of October 7, 2016, by the
Company (such acquisition, together with the other transactions contemplated by the Contribution Agreement, the “Business
Combination”).
At the closing of the Business Combination (the “Closing”), Silver Run contributed approximately $1.49 billion in cash to
CRP of which approximately $1.19 billion was then distributed to the Centennial Contributors for partial redemption of their
membership interests in CRP. At the Closing, Silver Run and the Centennial Contributors effected a recapitalization of CRP
pursuant to which (i) all of the remaining outstanding membership interests in CRP of the Centennial Contributors were converted
into 20,000,000 units representing common membership interests in CRP (the “CRP Common Units”) and (ii) the Company was
admitted as a member of CRP and issued 163,505,000 CRP Common Units, representing an approximate 89% interest in CRP.
The Business Combination was recorded using the acquisition method of accounting for business combinations. The
allocation of the purchase price has been finalized and was based upon management’s estimates and assumptions related to the
fair value of assets acquired and liabilities assumed on the Closing Date using currently available information.
The purchase price consideration for the Business Combination was as follows:
(in thousands)
Purchase price consideration:
Cash
Repayment of CRP long-term debt(1)
Total purchase price consideration
Fair value of non-controlling interest(2)
Total purchase price consideration and fair value of non-controlling interest
October 11, 2016
$
$
1,186,744
189,000
1,375,744
184,779
1,560,523
(1) Represents the additional contribution made by Silver Run to CRP in exchange for CRP Common Units to repay CRP’s outstanding
indebtedness at the Closing Date.
(2) Represents the fair value of the non-controlling interest (“NCI”) attributable to the Centennial Contributors. NCI is the portion of equity
(net assets) in a subsidiary not attributable, directly or indirectly, to Silver Run. In a business combination the NCI is recognized at its
acquisition date fair value. The fair value of the NCI at the Closing represented an 11% membership interest in CRP.
The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed:
(in thousands)
Fair value of assets acquired:
Other current assets
Derivative instruments
Oil and natural gas properties:
Proved properties
Unproved properties
Other property and equipment
Goodwill
Total fair value of assets acquired
Fair value of liabilities assumed:
Accounts payable and accrued expenses
Other current liabilities
Derivative instruments
Asset retirement obligation
Fair value of net assets acquired
$
October 11, 2016
13,341
1,052
444,551
1,138,423
1,764
—
1,599,131
30,156
63
3,400
4,989
78
$
1,560,523
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Unaudited Pro Forma Operating Results
The following unaudited pro forma combined financial information has been prepared as if the Business Combination and
other related transactions had taken place on January 1, 2015. The unaudited pro forma consolidated financial information has
been prepared using the acquisition method of accounting in accordance with GAAP.
The information reflects pro forma adjustments based on available information and certain assumptions that the Company
believes are reasonable, including depletion of CRP’s fair-valued proved oil and gas properties, and the estimated tax impacts of
the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2016, were adjusted to
exclude $18.7 million of transaction-related costs and $165.4 million of incentive unit compensation incurred by CRP.
The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily
indicative of the results that might have actually occurred had the Business Combination taken place on January 1, 2015;
furthermore, the financial information is not intended to be a projection of future results.
(in thousands)
Total net revenues
Total operating expenses
Net income (loss) attributable to common shareholders
Basic and diluted net income (loss) per share
Note 3—Property Acquisitions
2017 Acquisitions
(Unaudited Pro Forma)
Year Ended December 31,
2016
2015
$
$
98,833
$
86,490
1,666
0.01
$
90,460
123,702
(6,397)
(0.04)
On June 8, 2017, the Company completed the GMT Acquisition and acquired interests in 36 gross producing horizontal wells
plus undeveloped acreage on approximately 11,850 net acres (14,770 gross acres) in Lea County, New Mexico for an unadjusted
purchase price of $350.0 million. The Company operates approximately 79% of, and has an approximate 85% average working
interest in, this acreage. The acquired acres are located in the Northern Delaware Basin with drilling locations in the Avalon Shale,
2nd Bone Spring Sand, 3rd Bone Spring Sand and Wolfcamp A formations.
The GMT Acquisition was recorded as an asset acquisition under ASU 2017-01. Accordingly, the GMT purchase
consideration has been allocated to the GMT oil and natural gas properties based on their relative fair values measured as of the
acquisition date. After settlement statement adjustments of $0.1 million, the Company paid a net purchase price of $350.1 million.
On a relative fair value basis, $296.9 million was allocated to unproved properties and $53.2 million to proved properties with the
remaining purchase price allocated amongst other assets and liabilities. Transaction costs as they relate to the GMT Acquisition
mainly consist of advisory, legal and accounting fees and are capitalized as incurred, and the Company has incurred $0.5 million
in transaction costs related to this acquisition as of December 31, 2017.
2016 Acquisitions
On December 28, 2016, the Company acquired interests in 31 producing horizontal wells plus undeveloped acreage on
approximately 35,500 net acres (43,500 gross acres) located in Reeves County, Texas from Silverback Exploration, LLC, for an
unadjusted purchase price of $855.0 million, which consisted of cash consideration paid by the Company and a $32.3 million
payable at December 31, 2016 that was settled in 2017 when title issues relating to the purchased acreage were satisfied. The
Company operates approximately 90% of, and has an approximate 90% working interest in, this acreage. The Wolfcamp A and
Wolfcamp B are producing horizons on this acreage, and the Company believes that this acreage may be prospective for the
Wolfcamp C, Avalon and Bone Spring shale formations.
The Silverback Acquisition was recorded using the acquisition method of accounting for business combinations. The
allocation of the purchase price has been finalized and is based upon management’s estimates and assumptions related to the fair
value of assets acquired and liabilities assumed on the acquisition date using currently available information. Transaction costs
relating to this purchase were expensed as incurred. Since the acquisition date, the Company has recorded adjustments to
provisional amounts totaling $0.3 million. These adjustments did not have a material impact on the Company’s previously
reported consolidated financial statements, and therefore the Company has not retrospectively adjusted those financial statements.
79
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
The table below summarizes the allocation of the $867.8 million adjusted purchase price, based on the acquisition date fair
value of the assets acquired and the liabilities assumed as of December 31, 2017:
(in thousands)
Purchase price
Allocation of purchase price:
Unproved properties
Proved properties
Other property and equipment
Liabilities
Total
Silverback
Acquisition
$
867,772
753,763
116,700
56
(2,747)
867,772
$
In June 2016, the Company acquired undeveloped acreage and oil and gas producing properties located in Reeves County,
Texas. Total cash consideration paid by the Company was $33.0 million, including usual and customary post-closing adjustments.
Approximately $15.4 million was recorded as proved oil and natural gas properties. The assets include four operated producing
horizontal wells and approximately 1,580 net acres that directly offset the Company’s existing acreage in Reeves County, Texas.
(in thousands)
Cash consideration
Fair value of assets and liabilities acquired:
Proved oil and natural gas properties
Unproved oil and natural gas properties
Total fair value of oil and natural gas properties acquired
Revenue Suspense
Asset retirement obligation
Total fair value of net assets acquired
Note 4—Accounts Receivable, Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
(in thousands)
Oil and natural gas
Joint interest billings
Other
Accounts receivable, net
Accounts payable and accrued expenses are comprised of the following:
(in thousands)
Accounts payable
Accrued capital expenditures
Revenues payable
Accrued employee compensation and benefits
Accrued interest
Payable to Silverback
Accrued underwriting fees
Other
Accounts payable and accrued expenses
80
Predecessor
June 3, 2016
32,979
15,374
18,071
33,445
(400)
(66)
32,979
$
$
December 31, 2017
52,891
$
25,256
639
78,786
$
December 31, 2016
11,596
$
2,942
196
14,734
$
December 31, 2017
64,004
$
90,511
23,390
8,350
1,936
—
—
11,342
199,533
$
December 31, 2016
11,210
$
24,038
3,815
4,221
230
32,293
7,719
2,574
86,100
$
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 5—Long-Term Debt
Credit Agreement
CRP, the Company’s consolidated subsidiary, has a credit agreement with a syndicate of banks that as of December 31, 2017,
had a borrowing base of $475.0 million, which has been committed by lenders and is available for borrowing. A portion of the
revolving credit facility in an aggregate amount not to exceed $15.0 million may be used to issue letters of credit for the account
of CRP or other designated subsidiaries of the Company. As of December 31, 2017, the Company had no borrowings outstanding
and $474.1 million in available borrowing capacity, which was net of $0.9 million in letters of credit outstanding.
The amount available to be borrowed under CRP's revolving credit facility is subject to a borrowing base that is redetermined
semi-annually each April 1 and October 1 by the lenders in their sole discretion. CRP's credit agreement also allows
for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things,
the volumes of CRP’s proved oil and natural gas reserves, estimated cash flows from these reserves and its commodity hedge
positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of
permitted issued senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing
base, if borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a
portion of its debt outstanding under the credit agreement. Borrowings under CRP’s revolving credit facility are guaranteed by
certain of its subsidiaries. In connection with the October 2017 semi-annual redetermination, on November 2, 2017, the credit
agreement’s borrowing base was increased from $350.0 million to $575.0 million; however, on December 1, 2017 simultaneous
with the issuance of the Senior Notes, CRP entered into an amendment to the credit agreement to, among other things, reflect
CRP’s election to voluntarily reduce the commitments and borrowing base under the credit agreement to $475.0 million.
Interest and commitment fees are accrued based on a borrowing base utilization grid set forth in the credit agreement and are
discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources” in this report. Commitment fees are accrued on the unused portion of the aggregate lender commitment
amount and are included in interest expense in the Consolidated Statements of Operations. The credit facility provides for interest
only payments until October 15, 2019, when the credit agreement expires, and all outstanding borrowings are due.
CRP’s credit agreement contains restrictive covenants that limit its ability to, among other things: incur additional
indebtedness; make investments and loans; enter into mergers; make or declare dividends; enter into commodity hedges
exceeding a specified percentage of its expected production; enter into interest rate hedges exceeding a specified percentage of its
outstanding indebtedness; incur liens; sell assets; and engage in transactions with affiliates.
CRP’s credit agreement also requires it to maintain compliance with the following financial ratios: (i) a current ratio, which is
the ratio of CRP’s consolidated current assets (including unused commitments under its revolving credit facility and excluding
non-cash assets under FASB’s ASC Topic 815, Derivatives and Hedging (“ASC 815”), and certain restricted cash) to its
consolidated current liabilities (excluding the current portion of long-term debt under the credit agreement and non-cash liabilities
under ASC 815), of not less than 1.0 to 1.0; and (ii) a leverage ratio, which is the ratio of Total Funded Debt (as defined in CRP’s
credit agreement) to consolidated EBITDAX (as defined in CRP’s credit agreement) for the rolling four fiscal quarter period
ending on such day, of not greater than 4.0 to 1.0.
CRP was in compliance with the covenants and the financial ratios described above as of December 31, 2017 and through the
filing of this report.
5.375% Senior Unsecured Notes due 2026
On November 30, 2017, CRP issued at par $400.0 million of 5.375% senior notes due 2026 (the “Senior Notes”) in an 144A
private placement that resulted in net proceeds to CRP of $391 million, after deducting $9 million in debt issuance costs. Interest is
payable on the Senior Notes semi-annually in arrears on each January 15 and July 15, commencing July 15, 2018. The Senior Notes
are fully and unconditionally guaranteed on a senior unsecured basis by each of CRP’s current subsidiaries that guarantee CRP’s
revolving credit facility. The Senior Notes are not guaranteed by the Company nor is the Company subject to the terms of the indenture
governing the Senior Notes.
At any time prior to January 15, 2021, CRP may, on any one or more occasions, redeem up to 35% of the aggregate principal
amount of the Senior Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption
price equal to 105.375% of the principal amount of the Senior Notes redeemed, plus accrued and unpaid interest, if any, to the date
of redemption; provided that at least 65% of the aggregate principal amount issued under the indenture governing the Senior Notes
remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity
offering.
81
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
At any time prior to January 15, 2021, CRP may, on any one or more occasions, redeem all or a part of the Senior Notes at
a redemption price equal to 100% of the principal amount of the Senior Notes redeemed, plus a “make-whole” premium as of, and
accrued and unpaid interest, if any, to, the date of redemption. On and after January 15, 2021, CRP may redeem the Senior Notes,
in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 102.688% for the 12-month period
beginning on January 15, 2021, 101.344% for the 12-month period beginning January 15, 2022, and 100% beginning on January
15, 2023, plus accrued and unpaid interest to the redemption date.
If CRP experiences certain defined changes of control, each holder of the Senior Notes may require CRP to repurchase all
or a portion of its Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes, plus any
accrued but unpaid interest to the date of repurchase.
The indenture governing the Senior Notes contains covenants that, among other things and subject to certain exceptions
and qualifications, limit CRP’s ability and the ability of CRP’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness
or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated
indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict
dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets;
(viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with the covenants as
of December 31, 2017 and through the filing of this report.
Upon an Event of Default (as defined in the indenture governing the Senior Notes), the trustee or the holders of at least
25% of the aggregate principal amount of then outstanding Senior Notes may declare the Senior Notes immediately due and payable,
except that a default resulting from certain events of bankruptcy or insolvency with respect to CRP, any restricted subsidiary of CRP
that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary,
will automatically cause all outstanding Senior Notes to become due and payable.
Note 6—Income Taxes
In 2016, the Company became the sole managing member of CRP, and as a result, began consolidating the financial results of
CRP. CRP is treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership,
CRP is not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by CRP is
passed through to and included in the taxable income or loss of its members, including the Company, on a pro rata basis. The
Company is subject to U.S. federal income taxes, in addition to state and local income taxes with respect to its allocable share of
any taxable income or loss of CRP, as well as any stand-alone income or loss generated by the Company.
Income tax expenses and benefits included in the consolidated statements of operations are detailed below:
(in thousands)
Current taxes
Federal
State
Deferred taxes
Federal
State
Successor
Predecessor
Year Ended
December 31,
2017
October 11, 2016
through
December 31,
January 1, 2016
through
October 10, 2016
Year Ended
December 31,
2015
$
— $
—
—
(26,713)
(3,217)
(29,930)
—
—
—
—
—
—
—
$
$
— $
—
—
—
406
406
406
$
—
—
—
—
572
572
572
Income tax benefit (expense)
$
(29,930) $
82
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
A reconciliation of the statutory federal income tax expense to the income tax expense or benefit from continuing operations
provided at December 31, 2017, is as follows:
(in thousands)
Income tax (expense) benefit at the federal statutory rate
State income tax (expense) benefit - net of federal income tax
benefits
Change in Federal tax rate (net of state benefit and VA)
Excess depletion
Noncontrolling interest in partnership
Equity based compensation
Nondeductible expenses
Change in valuation allowance
Other
Successor
Predecessor
Year Ended
December 31,
2017
October 11, 2016
through
December 31, 2016
January 1, 2016
through
October 10, 2016
Year Ended
December 31,
2015
$
(39,720) $
3,145
$
— $
(2,788)
4,425
—
2,795
241
(31)
5,148
—
—
—
—
(273)
—
(4)
(2,868)
—
—
406
—
—
—
—
—
—
—
—
572
—
—
—
—
—
—
—
Income tax benefit (expense)
$
(29,930) $
$
406
$
572
The change in the Federal tax rate was due to the passage of Public Law No. 115-97, commonly referred to as the Jobs Act.
The passage of this legislation resulted in the Company generating a deferred tax benefit primarily due to the reduction in the U.S.
statutory rate from 35% to 21%. Based on the Company's current interpretation and subject to the release of the related
regulations and any future interpretive guidance, the Company believes the effects of the change in tax law incorporated herein
are substantially complete.
The tax effects of temporary differences that give rise to significant positions of the deferred income tax assets and liabilities
are presented below:
(in thousands)
Deferred tax assets:
Net operating loss carryforwards
Capitalized intangible drilling cost
Equity-based compensation
Other assets
Total deferred tax assets
Deferred tax liabilities:
Investment in Centennial Resource Production, LLC
Other liabilities
Total deferred tax liabilities
Valuation allowance
December 31, 2017
December 31, 2016
$
88,968
$
5,137
2,631
288
97,024
(106,923)
—
(106,923)
—
2,590
10,314
467
291
13,662
(8,514)
—
(8,514)
(5,148)
Net deferred tax asset (liabilities)
$
(9,899)
$
—
During 2017 in connection with the conversion of shares from a noncontrolling interest owner, a tax benefit was recorded in
equity of $20.0 million. For the period from October 11, 2016 through December 31, 2016 (Successor), equity was debited $5.6
million in connection with the issuance of shares from a noncontrolling interest owner. No tax benefit was recorded in equity as a
$2.0 million valuation allowance fully offset the attendant tax benefit.
As of December 31, 2017, the Company had approximately $415.9 million and $82.0 million of U.S. federal and state net
operating loss carryovers, respectively, which expire variously from 2035 to 2037.
The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize
its deferred income tax assets, including net operating loss carry forwards. In making this determination, the Company considers
83
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its
deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook
for future years. As of December 31, 2017, in part because the Company achieved cumulative pre-tax income, management
determined that sufficient positive evidence exists as of December 31, 2017, to conclude that it is more likely than not deferred
tax assets will be realized prior to their expiration.
The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations.
The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained
upon the examination by the Internal Revenue Service or other governmental agency. As of December 31, 2017, the Company did
not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for
uncertain tax positions during the next 12 months. Interest and penalties related to uncertain tax positions are reported in income
tax expense.
The Company is subject to the following material taxing jurisdictions: U.S., Colorado, New Mexico, and Texas. As of
December 31, 2017, the Company has no current tax years under audit. The Company remains subject to examination for federal
income taxes and state income taxes for tax years 2015 through 2017.
Note 7—Shareholders' Equity and Noncontrolling Interest
On November 9, 2017, Silver Run Sponsor, LLC (“Silver Run Sponsor”), the Riverstone Purchasers and Celero completed an
underwritten public offering of 25,000,000 shares of Class A Common Stock. No cash proceeds were received by the Company in
connection with this offering and 3,494,583 shares of Class C Common Stock were converted to shares of Class A Common Stock
on a one-to-one basis. In addition, a tax benefit of $20.0 million was recorded in equity as a result of the conversion of shares
from a noncontrolling interest owner.
On May 25, 2017, the Company’s stockholders approved at a special meeting the issuance of 26,100,000 shares of Class A
Common Stock upon the conversion of 104,400 shares of Series B Preferred Stock that were held by affiliates of Riverstone
Investment Group LLC in a private placement. There were no cash proceeds received by the Company in connection with this
issuance.
On May 4, 2017, the Company entered into subscription agreements with certain investors pursuant to which such investors
agreed to purchase, in the aggregate, 23,500,000 shares of Class A Common Stock at a purchase price of $14.50 per share, for
gross proceeds of approximately $340.8 million. The closing under the subscription agreements occurred concurrently with the
closing of the GMT Acquisition on June 8, 2017, and the proceeds were used to fund a majority of the purchase price of that
acquisition.
On December 28, 2016, in connection with the Silverback Acquisition, the Company 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 affiliates of Riverstone Investment
Group LLC and (ii) 33,012,380 shares of Class A Common Stock to certain other investors, resulting in net cash proceeds of
approximately $889.6 million. The Company used the proceeds from the private placements to fund the cash consideration for the
Silverback Acquisition and the remaining proceeds for general corporate purposes. The shares of Series B Preferred Stock were
subsequently converted into shares of the Company’s Class A Common Stock on a 250-to-one basis in 2017 as discussed above.
On October 11, 2016, in connection with Business combination, the Company issued and sold in private placements (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 accredited investors, resulting in net cash proceeds of approximately $1.0 billion. The outstanding
shares of Class B Common Stock converted into shares of Class A Common Stock on a one-for-one basis in connection with the
Business Combination. Additionally, the Company issued 20,000,000 shares of Class C Common Stock to the Centennial
Contributors and one share of Series A Preferred Stock to CRD in connection with the Business Combination.
Class A Common Stock
Holders of the Company's Class A Common Stock are entitled to one vote for each share held on all matters to be voted on
by the Company's stockholders. Holders of the Class A Common Stock and holders of the Class C Common Stock vote together
as a single class on all matters submitted to a vote of the Company's stockholders, except as required by law.
Unless specified in the Charter (including any certificate of designation of preferred stock) or Bylaws, or as required by
applicable provisions of the Delaware General Corporation Law or applicable stock exchange rules, the affirmative vote of a
majority of the Company’s shares of common stock that are voted is required to approve any such matter voted on by the
Company’s stockholders. There is no cumulative voting with respect to the election of directors, with the result that the holders of
more than 50% of the shares voted for the election of directors can elect all of the directors (subject to the right of the holder of
the Company’s Series A Preferred Stock to nominate and elect one director). Subject to the rights of the holders of any
84
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
outstanding series of preferred stock, the Company’s stockholders are entitled to receive ratable dividends when, as and if
declared by the board of directors out of funds legally available therefor.
In the event of a liquidation, dissolution or winding up of the Company, the holders of the Class A Common Stock are
entitled to share ratably in all assets remaining available for distribution to them after payment of liabilities and after provision is
made for each class of stock, if any, having preference over the Class A Common Stock. The Company’s stockholders have no
preemptive or other subscription rights. There are no sinking fund provisions applicable to the Class A Common Stock.
Class C Common Stock
The Company had 15,661,338 shares of Class C Common Stock outstanding as of December 31, 2017, which represent the
remaining portion of the 20,000,000 shares of Class C Common Stock issued to the Centennial Contributors in connection with
the Business Combination that had not been redeemed or exchanged as of such date.
Holders of Class C Common Stock have the right to vote on all matters properly submitted to a vote of the stockholders and
vote together as a single class with the holders of Class A Common Stock. In addition, the holders of Class C Common Stock,
voting as a separate class, are entitled to approve any amendment, alteration or repeal of any provision of the Company’s Charter
that would alter or change the powers, preferences or relative, participating, optional, other or special rights of the Class C
Common Stock. Holders of Class C Common Stock are not entitled to any dividends from the Company and are not entitled to
receive any of its assets in the event of any voluntary or involuntary liquidation, dissolution or winding up of its affairs.
Shares of Class C Common Stock may be issued only to the Centennial Contributors, their respective successors and assigns,
as well as any permitted transferees of the Centennial Contributors. A holder of Class C Common Stock may transfer shares of
Class C Common Stock to any transferee (other than the Company) only if such holder also simultaneously transfers an equal
number of such holder’s CRP Common Units to such transferee in compliance with the A&R LLC Agreement (as defined below).
Holders of Class C Common Stock generally have the right to cause CRP to redeem all or a portion of their CRP Common Units
in exchange for shares of the Company’s Class A Common Stock or, at CRP’s option, an equivalent amount of cash. The
Company may, however, at its option, effect a direct exchange of cash or Class A Common Stock for such CRP Common Units in
lieu of such a redemption by CRP. Upon the future redemption or exchange of CRP Common Units held by a Centennial
Contributor, a corresponding number of shares of Class C Common Stock will be canceled.
Preferred Stock
As of December 31, 2017 and 2016, the Company had one share of Series A Preferred Stock outstanding which was issued to
CRD in connection with the Business Combination. CRD, as the holder of the Series A Preferred Stock, is not entitled to any
dividends from the Company, but is entitled to preferred distributions in liquidation in the amount of $0.0001 per share of
Series A Preferred Stock and has a limited voting right as described below. The Series A Preferred Stock is redeemable by the
Company (i) at such time as CRD and its affiliates cease to own, in the aggregate, at least 5,000,000 CRP Common Units and/or
shares of Class A Common Stock (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar
transactions), (ii) at any time at CRD’s option or (iii) upon a breach by CRD of the transfer restrictions relating to the Series A
Preferred Stock. In addition, for so long as the Series A Preferred Stock remains outstanding, CRD will be entitled to nominate
one director for election to the Company’s board of directors in connection with any vote of the Company’s stockholders for the
election of directors, and the vote of CRD will be the only vote required to elect such nominee to the Company’s board of
directors.
Warrants
The Company’s Public Warrants were originally issued in connection with the IPO of Silver Run Acquisition Corporation. On
March 1, 2017, the Company delivered a notice of redemption to all holders of its Public Warrants announcing its intention to
redeem any Public Warrants that remained unexercised and outstanding after March 31, 2017 for $0.01 per Public Warrant. As of
December 31, 2017, all of the Company’s Public Warrants have been either exercised for shares of Class A Common Stock or
redeemed for $0.01 per Public Warrant. As a result of all such Warrants exercised, the Company issued in aggregate 6,235,790
shares of Class A common stock to holders of Public Warrants.
As of December 31, 2017, 8,000,000 Private Placement Warrants remained outstanding. Private Placement Warrants are non-
redeemable so long as they are held by Riverstone or its permitted transferees. Each whole Private Placement Warrant is
exercisable for one whole share of Class A Common Stock at a price of $11.50 per share. The warrants became exercisable on
March 1, 2017 and will expire five years after the completion of the Business Combination or earlier upon redemption or
liquidation.
85
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Noncontrolling Interest
The noncontrolling interest relates to CRP Common Units that were originally issued to the Centennial Contributors in
connection with the Business Combination and continue to be held by holders other than the Company. At the date of the
Business Combination, the noncontrolling interest held 10.9% of the ownership in CRP. The noncontrolling interest percentage is
affected by various equity transactions such as, Class C Common Stock conversions and Class A Common Stock activities.
As a result of the exchange of the CRP Common Units (and corresponding shares of Class C Common Stock) for Class A
Common Stock on October 11, 2016 and the issuance of shares of Class A Common Stock and Series B Preferred stock on
December 28, 2016 (as discussed in the preceding section above), the noncontrolling interest ownership of CRP decreased to
7.8% as of December 31, 2016.
As of December 31, 2017, the noncontrolling interest ownership of CRP decreased to 5.7%. The decrease was the result of
Class A Common Stock issuance in May and the exchange of CRP Common Units (and corresponding shares of Class C Common
Stock) for Class A Common Stock in November as discussed in preceding sections above.
The Company has consolidated the financial position, results of operations and cash flows of CRP and reflected that portion
retained by other holders of CRP Common Units as a noncontrolling interest. Refer to the Consolidated Statements of
Shareholders’ Equity for a summary of the activity attributable to the noncontrolling interest during the period.
Owners’ Equity (Predecessor)
At October 10, 2016 (prior to the Business Combination), members included Centennial HoldCo, Celero and Follow-On,
owning an approximate 61.2%, 21.2% and 17.6% membership interest in Centennial OpCo, respectively. CRP had two classes of
membership interests outstanding: Class A, which consisted of membership interests held by CRD and Follow-On; and Class B,
which consisted of membership interests held by Celero. On October 10, 2016 CRP recorded a deemed contribution attributable
to the consummation of the Business Combination, which resulted in the achievement of the payout conditions with respect to the
incentive units and CRP recorded $165.4 million of compensation expense. Refer to Note 7—Shareholders' Equity and
Noncontrolling Interest. Additionally, CRP recorded a deemed contribution of $14.0 million attributable to certain transaction
costs related to the Business Combination paid by the Centennial Contributors. Refer to Note 2—Business Combination.
As of December 31, 2015, CRD had contributed $289.4 million and had a remaining capital commitment of $32.5 million,
Follow-On had contributed $84.2 million and had a remaining capital commitment of $100.3 million, and Celero had contributed
$125.4 million and has no remaining capital commitment.
In 2015 Follow-On contributed $84.2 million to Centennial OpCo in exchange for membership interests in Centennial CRP.
In addition, CRD contributed approximately $27.2 million to CRP in exchange for additional membership interests in CRP.
Note 8—Stock-Based Compensation
Long Term Incentive Plan
On October 7, 2016, the stockholders of the Company approved the Centennial Resource Development, Inc. 2016 Long Term
Incentive Plan (the “LTIP”). An aggregate of 16,500,000 shares of Class A Common Stock were authorized for issuance under the
LTIP, and as of December 31, 2017, the Company had 10,851,807 shares of Class A Common Stock available for future grants.
The LTIP provides for grant of stock options (including incentive stock options and nonqualified stock options), stock
appreciation rights, restricted stock, dividend equivalents, restricted stock units and other stock or cash-based awards.
Stock-based compensation expense is recognized within General and administrative expenses and Exploration expense on the
Consolidated Statements of Operations as shown below. Historical amounts may not be representative of future amounts as the
value of future awards may vary from historical amounts. Upon adoption of ASU 2016-09 in October 2016, the Company elected
to account for forfeitures of awards granted under the LTIP as they occur in determining compensation expense.
(in thousands)
Restricted stock awards
Stock option awards
Performance Stock Units
Total stock-based compensation expense
Year Ended December
31, 2017
October 11, 2016
through
December 31, 2016
$
$
$
5,008
8,160
591
13,759
$
405
928
—
1,333
86
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Restricted Stock
The following table provides information about restricted stock awards outstanding during the year ended December 31,
2017:
Unvested balance as of December 31, 2016
Granted
Vested
Forfeited
Unvested balance as of December 31, 2017
Awards
Weighted Average
Grant-Date Fair Value
256,597
902,111
$
$
(137,177) $
(11,815) $
1,009,716
$
20.03
17.33
19.98
18.29
17.64
The Company grants service-based restricted stock awards to executive officers and employees, which generally vest ratably
over a three-year service period, and to directors, which generally vest over a one-year service period. Compensation cost for the
service-based restricted stock awards is based upon the grant-date market value of the award and such costs are recognized ratably
over the applicable vesting period. Weighted average grant-date fair value for restricted stock award granted was $17.33 per share
and $20.03 per share for the years ended December 31, 2017 and 2016, respectively. Total fair value of restricted stock awards
that vested during the year ended December 31, 2017 was $2.7 million. Unrecognized compensation cost related to unvested
restricted shares at December 31, 2017 was $15.1 million, which the Company expects to recognize over a weighted average
period of 2.3 years.
Stock Options
Stock options that have been granted under the LTIP expire ten years from the grant date and have service-based vesting
schedules of three years. The exercise price for an option under the LTIP is the closing price of the Company’s Class A Common
Stock as reported by NASDAQ on the date of grant.
Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the
applicable vesting period. The Company estimates the fair value using the Black-Scholes option-pricing model. Expected
volatilities are based on the re-levered asset volatility implied by a set of comparable companies. Expected term is based on the
simplified method and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant
date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.
The following table summarizes the assumptions and related information used to determine the grant-date fair value of stock
options awarded during the year ended December 31, 2017:
Weighted average grant-date fair value per share
Expected term (in years)
Expected stock volatility
Dividend yield
Risk-free interest rate
Year Ended
December 31,
2017
October 11,
2016 through
December 31,
2016
$
7.15
$
5.93
6
38%
—%
2.0%
6
40%
—%
1.5%
The following table provides information about stock option awards outstanding during the year ended December 31, 2017:
Outstanding as of December 31, 2016
Granted
Exercised
Forfeited
Outstanding as of December 31, 2017
Exercisable as of December 31, 2017
Options
Weighted Average
Exercise Price
Weighted Average
Remaining Term
(in years)
Aggregate
Intrinsic Value
(in thousands)
2,735,500
1,884,500
$
$
(58,499) $
(279,000) $
4,282,501
760,997
$
$
87
14.67
18.02
15.02
14.54
16.15
14.67
9.0
8.8
$
$
15,633
3,907
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
As of December 31, 2017, there was $18.9 million of unrecognized compensation cost related to non-vested stock options,
which the Company expects to recognize on a pro rata basis over a weighted average period of 2.0 years.
Performance Stock Units
The Company grants to executive officers performance stock units that are subject to market-based vesting criteria as well as
a three-year service period. Vesting at the end of the three-year service period is subject to the condition that the Company’s stock
price increases by a greater percentage, or decreases by a lesser percentage, than the average percentage increase or decrease,
respectively, of the stock prices of a peer group of companies. The market-based conditions must be met in order for the stock
awards to vest, and it is, therefore, possible that no shares could vest. However, the Company recognizes compensation expense
for the performance stock units subject to market conditions regardless of whether it becomes probable that these conditions will
be achieved or not and compensation expense is not reversed if vesting does not actually occur.
The grant-date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on
random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected
volatility was calculated based on the historical volatility of the common stock, and the risk-free interest rate is based on U.S.
Treasury yield curve rates with maturities consistent with the three-year vesting period. The following table summarizes the key
assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the
year ended December 31, 2017:
Number of simulations
Expected stock volatility
Dividend yield
Risk-free interest rate
Year Ended
December 31,
2017
1,000,000
41.6%
—%
1.5%
The following table provides information about performance stock units outstanding during the year ended December 31,
2017:
Unvested balance as of December 31, 2016
Granted
Vested
Forfeited
Unvested balance as of December 31, 2017
Awards
Weighted
Average Grant-
Date Fair Value
— $
193,391
$
— $
— $
—
21.53
—
—
193,391
$
21.53
As of December 31, 2017, there was $3.6 million of unrecognized compensation cost related to unvested performance stock
units, which the Company expects to recognize on a pro rata basis over a weighted average period of 2.5 years
Incentive Unit Compensation (Predecessor)
Certain employees of Centennial Resource Management, LLC, a wholly owned subsidiary of CRD at the time of grant,
received awards of CRD and NGP Follow-On incentive units, or profits interests. The incentive units were issued to employees in
return for services provided and cash payout was based, in part, on the value of Centennial’s equity. The incentive units were
accounted for as liability awards under ASC 718, with compensation expense based on period-end fair value and recognized at
such time that the payout terms were probable of being met. The consummation of the Business Combination resulted in the
achievement of the payout conditions with respect to the incentive units and CRP recorded $165.4 million of compensation
expense. No incentive compensation expense was recorded at December 31, 2015, because it was not probable that the
performance criterion would be met.
88
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 9—Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations and uses derivative instruments to
manage its exposure to commodity price risk from time to time.
Commodity Derivative Contracts
Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand
factors, worldwide political factors, general economic conditions and seasonal weather patterns. The Company periodically uses
derivative instruments, such as swaps, costless collars and basis swaps, to mitigate its exposure to declines in commodity prices
and to the corresponding negative impacts such declines can have on its cash flow from operations, returns on capital and other
financial results. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit
future revenues from favorable price changes. The Company does not enter into derivative contracts for speculative or trading
purposes.
Commodity Swap Contracts. The Company opportunistically uses commodity derivative instruments known as fixed price
swaps to realize a known price for a specific volume of production. All transactions are settled in cash with one party paying the
other for the net difference in the agreed upon published third-party index price (“index price”) and the swap fixed price,
multiplied by the contract volume. The Company also utilizes basis swaps contracts to hedge the difference between the index
price and a local index price.
The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in
place as of December 31, 2017:
Period
Volume (Bbl)
Weighted
Average
Differential ($/
Bbl) (1)
Crude oil basis swaps
January 2018 - June 2018
January 2018 - December 2018
905,000
1,825,000
$
$
0.18
0.00
The oil basis swap transactions are settled based on the difference between the arithmetic average of the ARGUS MIDLAND WTI and
ARGUS WTI CUSHING settlements, during the relevant calculation period.
Natural gas basis swaps
Period
Volume
(MMBtu)
Weighted
Average
Differential ($/
MMBtu) (1)
January 2018 - December 2018
January 2019 - December 2019
1,825,000
1,825,000
$
$
(0.43)
(0.43)
The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and
the NYMEX price of Natural Gas during the relevant calculation period.
(1)
(1)
Derivative Instrument Reporting. The Company’s oil and natural gas derivative instruments have not been designated as
hedges for accounting purposes; therefore, all gains and losses are recognized in the Company’s Consolidated Statements of
Operations. All derivative instruments are recorded at fair value on the Consolidated Balance Sheets, other than derivative
instruments that meet the “normal purchase normal sale” exclusion, and any gains and losses are recognized in current period
earnings.
The following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for
the periods presented:
(in thousands)
Successor
Predecessor
Year Ended
December 31,
2017
October 11,
2016
through
December 31,
2016
January 1,
2016
through
October 10,
2016
Year Ended
December 31,
2015
Net gain (loss) on derivative instruments
5,138
(1,548)
(6,838)
20,756
89
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives are measured at fair value and are
included in the accompanying Consolidated Balance Sheets as derivative assets and liabilities. The Company nets its financial
derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master netting agreements, which
provide for net settlement over the term of the contract and in the event of default or termination of the contract. The following
tables summarize the location and fair value amounts of all the Company’s derivative instruments in the Consolidated Balance
Sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the Consolidated Balance Sheets:
Derivative Assets
Derivative instruments
Derivative instruments
Total derivative assets
Derivative Liabilities
Derivative instruments
December 31, 2017
Gross Fair
Value Asset/
Liability
Amounts
Gross Amounts
Offset (1)
Net Recognized
Fair Value Assets/
Liabilities
$
$
$
720
662
1,382
527
$
$
$
(287) $
—
(287) $
433
662
1,095
(287) $
240
Balance Sheet
Classification
Current assets
Noncurrent assets
Current liabilities
(1)
The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and
derivative liabilities at settlement or in the event of a default under the agreements or contract termination.
Derivative Assets
Derivative instruments
Derivative Liabilities
Derivative instruments
Derivative instruments
Total derivative liabilities
December 31, 2016
Gross Fair
Value Asset/
Liability
Amounts
Gross Amounts
Offset (1)
Net Recognized
Fair Value Assets/
Liabilities
739
$
(308) $
431
5,669
20
(308)
—
5,689
$
(308) $
5,361
20
5,381
Balance Sheet
Classification
Current assets
Current liabilities
Noncurrent Liabilities
$
$
(1)
The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and
derivative liabilities at settlement or in the event of a default under the agreements or contract termination.
Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-
related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial
institutions that are lenders under CRP’s credit agreement. The Company uses only credit agreement participants to hedge with,
since these institutions are secured equally with the holders of any CRP bank debt, which eliminates the potential need to post
collateral when Centennial is in a derivative liability position. As a result, the Company is not required to post letters of credit or
corporate guarantees for its derivative counterparties in order to secure contract performance obligations.
In addition, the Company is exposed to credit risk associated with its derivative contracts from non-performance by its
counterparties. The Company mitigates its exposure to any single counterparty by contracting with a number of financial
institutions, each of which has a high credit rating and is a member of CRP’s credit facility as referenced above.
90
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 10—Fair Value Measurements
Recurring Fair Value Measurements
The Company follows FASB ASC Topic 820, Fair Value Measurement and Disclosure, which establishes a three-level
valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured
at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The
three levels are defined as follows:
•
•
•
Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices
(unadjusted) for identical assets or liabilities in active markets.
Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar
assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly,
for substantially the full term of the financial instrument.
Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the
fair value measurement.
The following table is a listing of the Company’s assets and liabilities that are measured at fair value and where they were
classified within the fair value hierarchy as of December 31, 2017 and December 31, 2016 (in thousands):
(in thousands)
Commodity derivative asset (liability), net
December 31, 2017
December 31, 2016
Level 1
Level 2
Level 3
$
$
— $
— $
855
$
(4,950) $
—
—
Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the
lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a
particular input to the fair value measurement in its entirety requires judgement and considers factors specific to the asset or
liability. The following is a description of the valuation methodologies used by the Company as well as the general classification
of such instruments pursuant to the above fair value hierarchy. There were no transfers between any of the fair value levels during
any period presented.
Derivatives
The Company uses Level 2 inputs to measure the fair value of oil and natural gas commodity derivatives. The Company uses
industry-standard models that consider various assumptions including current market and contractual prices for the underlying
instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures.
Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported
by observable data. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
Nonrecurring Fair Value Measurements
The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the
acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent
Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii)
production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v)
future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant
judgments and estimates by the Company’s management at the time of the valuation. Refer to Note 2—Business Combination and
Note 3—Property Acquisitions for additional information on the fair value of assets acquired during 2017 and 2016.
The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal
estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the
calculation of ARO include plugging costs and reserve lives. Refer to Note 11—Asset Retirement Obligations for additional
information on the Company’s ARO.
91
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Other Financial Instruments
The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities
approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying values
of the amounts outstanding under CRP’s credit agreement approximate fair value because its variable interest rates are tied to
current market rates and the applicable credit spreads represent current market rates for the credit risk profile of the Company. As
of December 31, 2017, the fair value of the Senior Notes was $407.5 million, which was determined using the quoted market
price, a Level 1 classification in the fair value hierarchy.
Note 11—Asset Retirement Obligations
The following table summarizes the changes in the Company’s asset retirement obligations for the periods presented:
(in thousands)
Asset retirement obligations, beginning of period
Additional liabilities incurred
Liabilities disposed
Liabilities settled
Accretion expense
Revision to estimated cash flows
Asset retirement obligations, end of period
Successor
Year Ended
December 31, 2017
October 11, 2016
through
December 31, 2016
Predecessor
January 1, 2016
through
October 10, 2016
7,226
2,219
(336)
(65)
516
2,601
12,161
$
4,989
2,189
—
(1)
49
—
7,226
$
$
2,288
240
—
(42)
134
32
2,652
ARO reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and natural
gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state
and federal laws. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate
settlement amounts, inflation factors, credit adjusted discount rates and timing of settlement. To the extent future revisions to
these assumptions impact the value of the existing ARO liability, a corresponding offsetting adjustment is made to the oil and
natural gas property balance.
Note 12—Transactions with Related Parties
Founder Shares
On November 6, 2015, Riverstone purchased 11,500,000 shares of Class B Common Stock (the “founder shares”) from the
Company, for an aggregate purchase price of $25,000, or approximately $0.002 per share. In February 2016, Riverstone
transferred 40,000 founder shares to each of the Company’s then independent directors (together with Riverstone, the “initial
stockholders”) at their original purchase price. On February 24, 2016, the Company effected a stock dividend of approximately
0.125 shares for each outstanding share of Class B Common Stock, resulting in the initial stockholders holding an aggregate of
12,937,000 founder shares. On April 8, 2016, following the expiration of the underwriters’ remaining over-allotment option in
connection with the Company’s IPO, Riverstone forfeited 437,500 founder shares, so that the remaining 12,500,000 founder
shares held by the initial stockholders would represent 20% of the Company’s then issued and outstanding shares of common
stock. On October 11, 2016, all of the outstanding founder shares were automatically converted into shares of Class A Common
Stock on a one-for-one basis in connection with the closing of the Business Combination.
Private Placement Warrants
On February 29, 2016, Riverstone purchased 8,000,000 Private Placement Warrants from the Company at a price of $1.50 per
whole warrant ($12.0 million in the aggregate) in a private placement that occurred simultaneously with the closing of the
Company’s IPO. Each whole Private Placement Warrant is exercisable for one whole share of Class A Common Stock at a price
of $11.50 per share. A portion of the purchase price of the Private Placement Warrants was placed in the Company’s trust account
along with the proceeds from its IPO. The Private Placement Warrants will expire at 5:00 p.m., New York City time, on October
11, 2021, or earlier upon redemption or our liquidation. Additionally, the Private Placement Warrants are non-redeemable and
exercisable on a cashless basis so long as they are held by Riverstone or its permitted transferees. If such Private Placement
Warrants are not held by Riverstone or its permitted transferees, we may call the Private Placement Warrants for redemption, in
whole and not in part, at a price of $0.01 per Private Placement Warrant, upon not less than 30 days’ prior written notice of such
92
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
redemption to each holder if the reported last sale price of our Class A Common Stock equals or exceeds $18.00 per share for any
20 trading days within a 30-day trading period ending three business days before we send the notice of redemption.
Amended and Restated Limited Liability Company Agreement of CRP
In connection with the closing of the Business Combination, on October 11, 2016, the Company and the Centennial
Contributors entered into CRP’s fifth amended and restated limited liability company agreement (as amended to date, the
“A&R LLC Agreement”) to, among other things, set forth our rights and obligations as holders of common membership interests
in CRP (the “CRP Common Units”). Under the A&R LLC Agreement, the Centennial Contributors generally have the right to
cause CRP to redeem all or a portion of their CRP Common Units in exchange for shares of our Class A Common Stock or, at
CRP’s option, an equivalent amount of cash; provided that we may, at our option, effect a direct exchange of cash or Class A
Common Stock for such CRP Common Units in lieu of such a redemption by CRP. Upon the future redemption or exchange of
CRP Common Units held by a Centennial Contributor, a corresponding number of shares of Class C Common Stock held by such
Centennial Contribution will be cancelled. The A&R LLC Agreement also includes provisions intended to ensure that we at all
times maintain a one-to-one ratio between (a) the number of outstanding shares of Class A Common Stock and the number of
CRP Common Units owned by us (subject to certain exceptions) and (b) the number of outstanding shares of our Class C
Common Stock and the number of CRP Common Units owned by the Centennial Contributors. This construct is intended to result
in the Centennial Contributors having a voting interest in the Company that is identical to the Centennial Contributors’ economic
interest in CRP.
Exchange Right
On October 11, 2016, following the closing of the Business Combination, the Company issued 844,079 shares of its Class A
Common Stock to an accredited investor at the direction of certain Centennial Contributors affiliated with such investor, in
exchange for 844,079 CRP Common Units held by such Centennial Contributors. The exchange was affected in accordance with
the A&R LLC Agreement. Upon the exchange of the CRP Common Units, the Company canceled 844,079 shares of its Class C
Common Stock held by the Centennial Contributors.
Amended and Restated Registration Rights Agreement
In connection with the closing of the Business Combination, on October 11, 2016, the Company entered into an amended and
restated registration rights agreement (the “Registration Rights Agreement”) with certain Riverstone entities, certain of its former
and current directors and the Centennial Contributors, pursuant to which such parties are entitled to certain registration rights
relating to the resale of certain securities held by them. In connection with the Registration Rights Agreement, the Company filed
a Registration Statement on Form S-3 that was declared effective on April 17, 2017.
Subscription Agreements
In connection with the Business Combination, on July 21, 2016, the Company entered into a subscription agreement with
Riverstone, pursuant to which Riverstone purchased 81,005,000 shares of Class A Common Stock at the closing of the Business
Combination for an aggregate purchase price of approximately $810.0 million.
In connection with the Silverback Acquisition, on November 27, 2016, the Company entered into a subscription agreement
with Riverstone, pursuant to which Riverstone agreed to purchase an aggregate of 3,473,590 shares of Class A Common Stock
and 104,400 shares of Series B Preferred Stock at the closing for an aggregate purchase price of approximately $430.0 million.
Pursuant to the terms thereof, the Series B Preferred Stock converted into 26,100,000 shares of Class A Common Stock on May
25, 2017.
Customer and Supplier Relationships
NGP Affiliated Companies
Beginning December 28, 2016, NGP and entities affiliated with NGP were no longer considered related parties of the
Company, and any expenses incurred on or after December 28, 2016 with NGP or its affiliates are no longer classified as related
party expenses. However, expenses incurred before December 28, 2016 with NGP or its affiliates were classified as related party
expenses as NGP beneficially owned more than 10% of equity interest in the Company. Such transactions are detailed below.
In May 2016, the Company acquired acreage in close proximity to its operating area in Reeves County, Texas and wellbore
only rights in an uncompleted horizontal wellbore for approximately $9.8 million from Caird DB, LLC, an affiliate of NGP. In
addition, the Company paid approximately $3.3 million during the year ended December 31, 2016, to RockPile Energy Services,
LLC (“Rockpile”). On July 3, 2017, Rockpile was acquired by an unrelated third party and is no longer an affiliate of NGP.
93
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Riverstone Affiliated Companies
Riverstone and its affiliates beneficially own more than 10% of equity interest in the Company and are therefore considered
related parties. From time to time, the Company obtains services related to its drilling and completion activities from affiliates of
Riverstone. In particular, the Company has paid the following amounts to the following affiliates of Riverstone for such services:
(i) approximately $72.6 million and $8.2 million during the years ended December 31, 2017 and December 31, 2016, respectively,
to Liberty Oilfield Services, LLC (“Liberty”); and (ii) approximately $6.4 million and $1.4 million during the years ended
December 31, 2017 and December 31, 2016, respectively, to Permian Tank and Manufacturing, Inc. (“Permian”). Included in
Accounts payable and accrued expenses was $0.3 million and $0.4 million due to Permian as of December 31, 2017 and
December 31, 2016, respectively, and $3.1 million due to Liberty as of December 31, 2016.
Other Affiliated Companies
Mark G. Papa, President, Chief Executive Officer and Chairman of the Board, serves as a director and Chairman of the Board
of Oil States International, Inc., an energy services company publicly traded on the New York Stock Exchange (“Oil States”).
From time to time, the Company obtains services related to drilling and completion activities from Oil States. In particular, the
Company paid approximately $10.5 million and $1.2 million during the years ended December 31, 2017 and December 31, 2016,
respectively, to Oil States. Included in Accounts payable and accrued expenses was $1.5 million and $0.2 million due to Oil
States as of December 31, 2017 and December 31, 2016, respectively.
Note 13—Commitments and Contingencies
Operating Leases and Other Commitments
The following is a schedule of the Company’s future minimum lease payments with commitments that have initial or
remaining non-cancelable lease terms in excess of one year as of December 31, 2017:
(in thousands)
Drilling rig commitments
Office leases
Water disposal agreement
Purchase obligations
Transportation and gathering
Total
Drilling Rig Contracts
2018
2019
2020
2021
2022
Thereafter
Total
$ 19,714
$
1,620
$
— $
— $
— $
— $
21,334
2,360
1,825
4,400
2,044
2,322
1,825
13,200
2,044
2,163
1,825
8,800
—
2,073
1,825
—
—
274
—
—
—
—
—
—
—
9,192
7,300
26,400
4,088
$ 30,343
$
21,011
$
12,788
$
3,898
$
274
$
— $
68,314
As of December 31, 2017, the Company had six drilling rigs under contract and its obligations under these agreements are
included in the above schedule. Early termination of these contracts would require termination penalties of $14.7 million to be
paid as of December 31, 2017, which would be paid in lieu of paying the remaining drilling commitments under these contracts.
The Company recognized $38.0 million, $1.0 million and $2.0 million for the year ended December 31, 2017, the periods from
October 11, 2016, through December 31, 2016, and January 1, 2016, through October 10, 2016, respectively, under these long-
term contracts, which are initially capitalized as a component of oil and gas properties and either depleted in future periods or
written off as exploration expense.
Office Leases
The Company leases office space in Colorado, Texas, and New Mexico. The Company recognized rent expense of $1.1
million, $0.1 million, $0.4 million, and $0.4 million for the year ended December 31, 2017, the periods from October 11, 2016,
through December 31, 2016, and January 1, 2016, through October 10, 2016, and for the year ended December 31, 2015,
respectively.
Water Disposal Agreement
In January 2017, the Company entered into a water disposal agreement for transportation and disposal of produced water
from its operated wells. Under the terms of the agreement, Centennial is obligated to provide a minimum volume of produced
water or else pay for any deficiencies at the price stipulated in the contract. The obligations reported above represent the
minimum financial commitments pursuant to the terms of this contract as of December 31, 2017. Actual expenditures under this
contract may exceed the minimum commitments presented above. The Company recognized water disposal costs of $2.4 million
for the year ended December 31, 2017 related to this contract.
94
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Purchase Obligations
In July 2017, the Company entered into a supply agreement to purchase frac and sand product for a term of three years.
Under the terms of the agreement, Centennial is obligated to purchase a minimum volume of frac and sand product at a fixed sales
price. A prepayment of $13.2 million was made during 2017 and will be used as a partial credit against monthly purchases. The
obligations reported above represent our minimum financial commitments pursuant to the terms of this contract as of
December 31, 2017. Actual expenditures under this contract may exceed the minimum commitments presented above. The
Company paid $13.2 million for the year ended December 31, 2017 under this contract for advance purchases of frac and sand
product of which $1.6 million was capitalized as incurred during the year.
Transportation and Gathering Agreement
In June 2017, the Company entered into a transportation service agreement through December 31, 2019 whereby it is
required to deliver 40,000 MMBtu per day or pay for any deficiencies at the price stipulated in the contract. This delivery
commitment is tied to the Company’s natural gas production in Reeves and Ward counties, Texas. The obligations reported above
represent the minimum financial commitments pursuant to the terms of this contract as of December 31, 2017. Actual
expenditures under this contract may exceed the minimum commitments presented above. The Company recognized
transportation and gathering expenses of $1.2 million for the year ended December 31, 2017 related to this contract.
In December 2015, the Company entered into a transportation and gathering services agreement by which a transporter
agreed to construct a crude oil gathering and transportation system capable of transporting crude oil from certain Company wells
in Pecos, Reeves and Ward Counties, Texas to destination points in Crane and Midland, Texas (the “Transportation System”), and
the Company agreed to dedicate and ship on the Transportation System all crude oil owned or controlled by the Company from oil
and gas leases covering approximately 62,913 gross acres located within a designated area of mutual interest in Pecos, Reeves and
Ward Counties. The agreement has a primary term of 12 years from October 1, 2016, the date the Transportation System was first
put into service and may be extended at the Company’s option for two successive two-year terms and, thereafter, is automatically
extended for successive one-year terms unless terminated by the Company or the transporter upon 60 days’ prior notice.
Contingencies
The Company may at times be subject to various commercial or regulatory claims, litigation or other legal proceedings that
arise in the ordinary course of business. While the outcome of these lawsuits and claims cannot be predicted with
certainty, management believes it is remote that the impact of such matters that are reasonably possible to occur will have a
material adverse effect on the Company’s financial position, results of operations or cash flows. Management is unaware of any
pending litigation brought against the Company requiring the reserve of a contingent liability as of the date of these consolidated
financial statements.
Note 14—Subsequent events
On January 5, 2018, the Company entered into a purchase and sale agreement to sell approximately 8,600 undeveloped net
acres and 12 gross producing wells located in Reeves County, Texas for a total sale price of $140.7 million, subject to certain
post-closing adjustments. The divested acreage represents a largely non-operated position (average 32% WI) on the western
portion of Centennial’s position in Reeves County. The net book value of the properties being sold approximates the sales price as
of December 31, 2017, which primarily consists of oil and gas properties and property, plant and equipment included in the
Consolidated Balance Sheet. The transaction is expected to close on March 1, 2018.
On February 8, 2018, the Company completed the acquisition of approximately 4,000 undeveloped net acres, as well as
certain producing properties, in the Northern Delaware Basin in Lea County, New Mexico for an unadjusted purchase price of
$94.7 million. The operated acreage position contains an average 95% working interest and is largely contiguous to Centennial’s
existing position. Pursuant to the agreements, the Company placed $8.6 million cash in escrow accounts one business day after
the signing of the agreements on December 21, 2017 and such deposits were applied as part of the payment of the purchase price
upon closing of the transactions. The Company presented the cash in escrow as restricted cash within the line item Other
Noncurrent Assets on the Consolidated Balance Sheet as of December 31, 2017.
95
Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited)
Capitalized Costs
The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of
accumulated depreciation, depletion and amortization are shown below:
(in thousands)
Proved properties
Unproved properties
Total proved and unproved properties
Accumulated depreciation, depletion and amortization
Net capitalized costs
Costs Incurred For Oil and Natural Gas Producing Activities
December 31, 2017
December 31, 2016
$
$
1,602,002
$
1,952,680
3,554,682
(173,906)
3,380,776
$
604,022
1,905,661
2,509,683
(14,436)
2,495,247
The costs incurred in the Company’s oil and gas production, exploration, and development activities are displayed in the table
below and include costs whether capitalized or expensed as well as revisions and additions to the estimated future asset retirement
obligations.
(in thousands)
Acquisition costs:
Proved properties
Unproved properties
Development costs
Exploration costs
Total
Successor
Predecessor
Year Ended
December 31,
2017
October 11, 2016
through
December 31, 2016
January 1, 2016
through
October 10, 2016
Year ended
December 31,
2015
$
54,550
$
561,251
$
16,386
$
350,567
585,866
21,542
1,905,660
44,602
1,468
39,399
53,512
920
14,268
28,955
87,452
84
$
1,012,525
$
2,512,981
$
110,217
$
130,759
Results of Oil and Natural Gas Producing Activities
The results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) are
presented below:
(in thousands)
Revenues:
Successor
Predecessor
Year Ended
December 31,
2017
October 11, 2016
through
December 31, 2016
January 1, 2016
through
October 10, 2016
Year ended
December 31,
2015
Oil, natural gas and NGL sales
$
429,902
$
29,717
$
69,116
$
90,460
Costs:
Lease operating expenses
Severance and ad valorem taxes
Gathering, processing and transportation expenses
Depreciation, depletion and amortization
Impairment and abandonment expenses
Exploration expense
Contract termination and rig stacking
Income tax (expense) benefit
41,336
23,173
34,259
161,628
(29)
14,373
—
29,930
3,541
1,636
2,187
14,877
—
1,468
—
—
11,036
3,696
4,583
62,964
2,545
920
—
(406)
21,173
5,021
5,732
90,084
7,619
84
2,387
(572)
Results of operations
$
125,232
$
6,008
$
(16,222) $
(41,068)
Estimated Quantities of Proved Oil and Gas Reserves
The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and
natural gas producing activities and SEC Regulation S-X for oil and natural gas reporting reserves estimation and disclosure. The
Company retained Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm, to prepare the estimates of
96
all of its proved reserves as of December 31, 2017, 2016 and 2015. The individuals performing reserves estimates possess
professional qualifications and demonstrate competency in reserves estimation and evaluation. The estimates of proved reserves
are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and
development, price changes and other factors.
Reserve estimates are based on an unweighted arithmetic average of commodity prices during the 12-month period, using the
closing prices on the first day of each month, as defined by the SEC. The following prices, as adjusted for transportation, quality,
and basis differentials, were used in the calculation of the standardized measure of discounted future net cash flows
(“standardized measure”):
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Successor
Predecessor
Year Ended
December 31,
2017
October 11, 2016
through
December 31, 2016
January 1, 2016
through
October 10, 2016
Year ended
December 31,
2015
$
48.43
$
2.74
25.92
38.49
0.98
14.59
$
36.98
$
1.24
13.28
41.85
1.71
13.94
97
As of December 31, 2017, all of the Company’s oil and gas reserves are attributable to properties within the United States.
The table below presents a summary of changes in quantities of proved oil and gas reserves in the Company’s estimated proved
reserves:
Crude Oil
(MBbls)
Natural Gas
(MMcf)
Natural Gas
Liquids
(MBbls)
Total (MBoe)
Total proved reserves:
Balance - January 1, 2015 (Predecessor)
Extensions and discoveries
Revisions to previous estimates
Purchases of reserves in place
Production
Balance - December 31, 2015 (Predecessor)
Extensions and discoveries
Revisions to previous estimates
Purchases of reserves in place
Production
Balance - October 11, 2016 (Predecessor)
Extensions and discoveries
Revisions to previous estimates
Purchases of reserves in place
Production
Balance - December 31, 2016 (Successor)
Extensions and discoveries
Revisions to previous estimates
Purchases of reserves in place
Divestitures of reserves in place
Production
19,850
9,444
(5,109)
844
(1,830)
23,199
5,851
1,025
1,600
(1,584)
30,091
7,063
184
9,651
(523)
46,466
47,870
10,751
3,211
(371)
(6,994)
Balance - December 31, 2017 (Successor)
100,933
Proved developed reserves:
December 31, 2014
December 31, 2015
October 11, 2016
December 31, 2016
December 31, 2017
Proved undeveloped reserves:
December 31, 2014
December 31, 2015
October 11, 2016
December 31, 2016
December 31, 2017
8,026
9,347
11,346
14,551
41,786
11,823
13,852
18,745
31,914
59,147
27,414
11,927
(5,204)
1,363
(3,058)
32,442
6,410
(1,521)
2,130
(2,660)
36,801
12,219
16,445
83,992
(1,113)
148,344
174,458
16,154
6,822
(812)
(17,754)
327,212
11,959
12,711
14,973
42,190
126,065
15,455
19,731
21,828
106,154
201,147
1,551
1,432
995
204
(331)
3,851
773
(110)
245
(253)
4,506
1,225
983
5,152
(96)
11,770
17,465
3,114
435
(120)
(1,678)
30,986
766
1,603
1,927
3,618
12,133
785
2,248
2,579
8,152
25,970
12,864
(4,981)
1,275
(2,671)
32,457
7,692
662
2,200
(2,280)
40,731
10,325
3,906
28,802
(805)
82,959
94,411
16,556
4,784
(626)
(11,630)
186,454
10,785
13,068
15,769
25,200
74,929
15,184
19,389
24,962
57,759
18,853
111,525
Notable changes in proved reserves for the year ended December 31, 2017 included the following:
•
•
Extensions and discoveries. In 2017, total extensions and discoveries of 94.4 MMBoe were primarily attributable to increased
drilling activity as a result of the Company’s six-rig drilling program effective throughout the year. These additions include
66.6 MMBoe in PUDs and 27.8 MMBoe in the conversion of unproved locations to PDP wells primarily in the Upper
Wolfcamp A zone.
Revisions to previous estimates. In 2017, revisions to previous estimates of 16.6 MMBoe are composed of positive revisions
of 26.4 MMBoe primarily relating to adjustments to PUD well locations scheduled to be drilled at longer lateral lengths as
98
well as additional positive performance revisions attributable to more wells drilled with longer lateral lengths in 2017. These
positive revisions were partially offset by 9.8 MMBoe of negative revisions associated with PUD reclassification to unproven
reserves as they are no longer expected to be developed within the five years of their initial recording in accordance with SEC
rules.
•
Purchases of reserves in place. In 2017, purchases of reserves of 4.8 MMBoe was primarily attributable to the GMT
Acquisition in June. Refer to Note 3—Property Acquisitions for further details.
Notable changes in proved reserves for the period from October 11, 2016 to December 31, 2016 included the following:
•
•
•
Extensions and discoveries. During the period, total extensions and discoveries were primarily attributable to 10.3 MMBoe
proved reserves added as a result of drilling activity.
Revisions to previous estimates. During the period, revisions to previous estimates were primarily attributable to 3.9 MMBoe
due to improved results in completion techniques and adjustments of natural gas and NGL treatment through the gas plants.
Purchases of reserves in place. During the period, purchases of proved reserves primarily attributable to the acquisition of
28.8 MMBoe as a result of Silverback Acquisition in December 2016. Refer to Note 3—Property Acquisitions for further
details.
Notable changes in proved reserves for the period from January 1, 2016 to October 10, 2016 included the following:
•
•
•
Extensions and discoveries. During the period, total extensions and discoveries were primarily attributable to 7.7 MMBoe
proved reserves added as a result of drilling activity.
Revisions to previous estimates. During the period, revisions to previous estimates were primarily attributable to 0.7 MMBoe
due to positive performance revisions.
Purchases of reserves in place. During the period, purchases of reserves primarily attributable 2.2 MMBoe of proved reserves
in the Reeves County, Texas. Refer to Note 3—Property Acquisitions for further details.
Notable changes in proved reserves for the year ended December 31, 2015 included the following:
•
•
•
Extensions and discoveries. During the period, total extensions and discoveries were primarily attributable to 12.9 MMBoe
proved reserves added as a result of drilling activity.
Revisions to previous estimates. In 2015, revisions to previous estimates were primarily attributable to negative revisions of
5.0 MMBoe. The significant decrease in commodity prices seen in 2015 resulted in negative revisions related to the
conversion of approximately 6.8 MMBoe from PUDs to unproved reserves, partially offset by a positive revision in
performance.
Purchases of reserves in place. In 2015, purchases of reserves primarily attributable 1.3 MMBoe of proved reserves in the
Delaware Basin in September 2015.
99
Standardized Measure of Discounted Future Net Cash Flows
As required by FASB ASC Topic 932, Extractive Activities - Oil and Gas, the standardized measure of discounted future net
cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount
factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and
rehabilitation obligations. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax
net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses
give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. This
calculation does not necessarily result in an estimate of the fair value of the Company’s oil and gas properties.
The following table presents the Company’s standardized measure of discounted future net cash flows:
(in thousands)
Future cash inflows
Future development costs
Future production costs
Future income tax expenses
Future net cash flows
10% discount to reflect timing of cash flows
Successor
Predecessor
Year Ended
December 31,
2017
October 11, 2016
through
December 31, 2016
January 1, 2016
through
October 10, 2016
Year ended
December 31,
2015
$
6,586,516
$
2,105,585
$
1,217,641
$
1,079,962
(880,767)
(2,233,266)
(542,587)
2,929,896
(1,426,570)
(482,162)
(640,306)
(136,587)
846,530
(471,438)
(297,559)
(413,410)
(5,614)
501,058
(291,345)
(277,837)
(450,058)
(6,643)
345,424
(210,355)
Standardized measure of discounted future net cash flows
$
1,503,326
$
375,092
$
209,713
$
135,069
The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:
(in thousands)
Standardized measure of discounted future net cash flows,
beginning of period
Sales of oil, natural gas and NGLs, net of production
costs
Purchase of minerals in place
Divestiture of minerals in place
Extensions and discoveries, net of future development
costs
Previously estimated development costs incurred during
the period
Net change in prices and production costs
Change in estimated future development costs
Revisions of previous quantity estimates
Accretion of discount
Net change in income taxes
Net change in timing of production and other
Standardized measure of discounted future net cash flows,
end of period
Successor
Predecessor
Year Ended
December 31,
2017
October 11, 2016
through
December 31, 2016
January 1, 2016
through
October 10, 2016
Year ended
December 31,
2015
$
375,092
$
209,713
$
135,069
$
365,883
(331,134)
56,658
(4,607)
842,756
139,246
281,026
(60,301)
253,399
42,753
(156,574)
65,012
(22,354)
127,842
—
55,825
10,891
(978)
571
20,190
4,753
(47,990)
16,629
(49,801)
10,145
—
46,438
11,743
6,661
28,998
3,673
11,319
(1,568)
7,036
(58,534)
14,416
—
57,894
16,100
(494,734)
247,642
(51,342)
37,517
1,601
(1,374)
$
1,503,326
$
375,092
$
209,713
$
135,069
100
Selected Quarterly Financial Data (Unaudited)
(in thousands)
2017
Net revenues
Operating expenses
Total operating income (loss)
Other income (expense)
Income tax (expense) benefit
Net income (loss) attributable to common shareholders
Income (loss) per share:
Basic
Diluted
Successor
Quarters Ended
March 31
June 30
September 30
December 31
$
61,097
$
91,064
$
111,611
$
53,905
7,192
3,515
—
9,823
67,810
23,254
9,013
(9,069)
20,762
85,066
26,545
(2,052)
(8,233)
14,447
166,130
117,841
48,289
(2,271)
(12,628)
30,536
$
$
0.04
0.04
$
$
0.09
0.09
$
$
0.06
0.06
$
$
0.12
0.12
(in thousands)
2016
Net revenues
Operating expenses
Total operating income (loss)
Other income (expense)
Income tax (expense) benefit
Net income (loss)
Income (loss) per share:
Basic
Diluted
Predecessor
Periods Ended
Successor
Period Ended
March 31
June 30
September 30
October 1, 2016
through
October 10, 2016
October 11, 2016
through
December 31, 2016
$
15,121
$
23,347
$
27,321
$
3,327
$
29,855
(14,734)
273
—
30,251
(6,904)
(9,635)
406
32,228
(4,907)
(227)
—
183,465
(180,138)
(2,858)
—
(14,461)
(16,133)
(5,134)
(182,996)
$
$
29,717
36,800
(7,083)
(1,902)
—
(8,081)
(0.05)
(0.05)
101
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, the Company has evaluated, under the supervision and with the
participation of management, including the principal executive officer and principal financial officer, the effectiveness of the
design and operation of disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act)
as of December 31, 2017. Our disclosure controls and procedures are designed to provide reasonable assurance that the
information required to be disclosed in reports that the Company files under the Exchange Act is accumulated and communicated
to management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions
regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules
and forms of the SEC. Based upon that evaluation, the principal executive officer and principal financial officer concluded that
the Company’s disclosure controls and procedures were effective as of December 31, 2017 at the reasonable assurance level.
Management’s Annual Report on Internal Control Over Financial Reporting
Management, including the principal executive officer and principal financial officer, is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. The
Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of the consolidated financial statements for external purposes in accordance with GAAP.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2017,
using the criteria in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Based on this evaluation, management believes that the Company’s internal control over
financial reporting was effective as of December 31, 2017.
This Annual Report on Form 10-K includes an attestation report of KPMG LLP, the Company’s independent registered public
accounting firm, on the Company’s internal control over financial reporting as of December 31, 2017, which is included in this
Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting
There were no changes in the system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule
15d-15(f) under the Exchange Act) during the quarter ended December 31, 2017 that have materially affected, or are reasonably
likely to materially affect, the Company’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
102
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required in response to this item will be set forth in our definitive proxy statement for the 2018 annual
meeting of stockholders and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required in response to this item will be set forth in our definitive proxy statement for the 2018 annual
meeting of stockholders and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
The information required in response to this item will be set forth in our definitive proxy statement for the 2018 annual
meeting of stockholders and is incorporated herein by reference.
103
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required in response to this item will be set forth in our definitive proxy statement for the 2018 annual
meeting of stockholders and is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required in response to this item will be set forth in our definitive proxy statement for the 2018 annual
meeting of stockholders and is incorporated herein by reference.
104
ITEM 15. EXHIBITS AND FINANCIAL STATEMENTS SCHEDULES
PART IV
(a)(1) The following financial statements are included in Part II, Item 8 of this Annual Report on Form 10-K:
Consolidated Balance Sheets as of December 31, 2017 and 2016
Consolidated Statements of Operations for the year ended December 31, 2017, the periods October 11, 2016 through
December 31, 2016 and January 1, 2016 through October 10, 2016, and the year ended December 31, 2015
Consolidated Statements of Cash Flows for the year ended December 31, 2017, the periods October 11, 2016 through
December 31, 2016, and January 1, 2016 through October 10, 2016, and the year ended December 31, 2015
Consolidated Statements of Shareholders’ Equity for the year ended December 31, 2017 and the period October 10, 2016
through December 31, 2016 and the Consolidated Statements of Owners’ Equity for the period January 1, 2016 through
October 10, 2016 and the year ended December 31, 2015
Notes to Consolidated Financial Statements for the year ended December 31, 2017, the periods from October 11, 2016 through
December 31, 2016 and January 1, 2016 through October 10, 2016, and the year ended December 31, 2015
Page
65
66
67
69
71
(2) Financial statement schedules—None
(3) Exhibits:
Exhibit
Number
Description of Exhibits
2.1 Contribution Agreement, dated as of July 6, 2016, as amended by Amendment No. 1 thereto, dated as of July 29, 2016, among
Centennial Resource Development, LLC, NGP Centennial Follow-On LLC, Celero Energy Company, LP, Centennial Resource
Production, LLC and New Centennial, LLC (incorporated by reference to Annex A of the Registrant’s definitive proxy statement
filed with the SEC on September 23, 2016).
2.2 Purchase and Sale Agreement, dated as of November 21, 2016, by and among SB RS Holdings, LLC, Silverback Exploration,
LLC and Silverback Operating, LLC (incorporated by reference to Exhibit 2.2 to the Registrant’s Registration Statement
on Form S-1 (Registration No. 333-215621) filed with the SEC on January 19, 2017).
2.3 Purchase and Sale Agreement, dated as of April 28, 2017, by and between GMT Exploration Company LLC and Centennial
Resource Production, LLC (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with
the SEC on May 1, 2017).
3.1 Second Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Registrant’s Current
Report on Form 8-K filed with the SEC on October 11, 2016).
3.2 Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed
with the SEC on October 7, 2016).
3.3 Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC dated as of
October 11, 2016 (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed with the
SEC on October 11, 2016).
3.4 Amendment No. 1 to Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production,
LLC dated as of December 28, 2016 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K
filed with the SEC on December 29, 2016).
3.5 Amendment No. 2 to Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production,
LLC dated as of March 20, 2017 (incorporated by reference to Exhibit 3.5 to the Registrant’s Annual Report on Form 10-K
filed with the SEC on March 23, 2017).
4.1 Specimen Class A Common Stock Certificate (incorporated by reference to Exhibit 4.2 to the Registrant’s Registration
Statement on Form S-1 (Registration No. 333-209140) filed with the SEC on January 27, 2016).
4.2 Specimen Warrant Certificate (incorporated by reference to Exhibit 4.3 to the Registrant’s Registration Statement on
Form S-1 (Registration No. 333-209140) filed with the SEC on January 27, 2016).
4.3 Warrant Agreement between Continental Stock Transfer & Trust Company and the Registrant (incorporated by reference to
Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 29, 2016).
4.4 Certificate of Designation of Series A Preferred Stock (incorporated by reference to Exhibit 3.2 to the Registrant’s
Current Report on Form 8-K filed with the SEC on October 11, 2016).
4.5
Indenture, dated as of November 30, 2017, by and among Centennial Resource Production, LLC, the subsidiary guarantors
named therein and UMB Bank, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on
Form 8-K, filed with the SEC on December 5, 2017).
10.1 Amended and Restated Registration Rights Agreement among the Registrant and certain stockholders (incorporated by reference
to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on October 11, 2016).
105
10.2 Sponsor Warrants Purchase Agreement, dated February 23, 2016, between the Registrant and Silver Run Sponsor, LLC
(incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed with the SEC on February 29,
2016).
10.3 Form of Indemnity Agreement (incorporated by reference to Exhibit 10.7 to the Registrant’s Registration Statement on Form S-1
(Registration No. 333-209140) filed with the SEC on January 27, 2016).
10.4 Amended and Restated Credit Agreement, dated as of October 15, 2014, among Centennial Resource Production, LLC, as
borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to
Exhibit 10.1 to the Registration Statement on Form S-1 of Centennial Resource Development, Inc. (Registration
No. 333-212185) filed with the SEC on June 22, 2016).
10.5 First Amendment to Amended and Restated Credit Agreement, dated as of May 6, 2015, among Centennial Resource
Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and guarantors
party thereto (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-1 of Centennial Resource
Development, Inc. (Registration No. 333-212185) filed with the SEC on June 22, 2016).
10.6 Second Amendment to Amended and Restated Credit Agreement, dated as of October 11, 2016, by and among Centennial
Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and
guarantors party thereto (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the
SEC on October 11, 2016).
10.7 Third Amendment to Amended and Restated Credit Agreement, dated as of December 28, 2016, by and among Centennial
Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and
guarantors party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with
the SEC on January 4, 2017).
10.8 Fourth Amendment to Amended and Restated Credit Agreement, dated as of April 28, 2017, by and among Centennial Resource
Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and guarantors party
thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 1,
2017).
10.9 Fifth Amendment to Amended and Restated Credit Agreement, dated as of November 2, 2017, by and among Centennial
Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and
guarantors party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with
the SEC on November 3, 2017).
10.10 Limited Consent and Sixth Amendment to Amended and Restated Credit Agreement, dated as of November 10, 2017, by and
among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the
lenders and guarantors party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K
filed with the SEC on November 14, 2017).
10.11 Seventh Amendment to Amended and Restated Credit Agreement, dated as of December 1, 2017, by and among Centennial
Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and
guarantors party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with
the SEC on December 5, 2017).
10.12# Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the
Registrant’s Current Report on Form 8-K filed with the SEC on October 11, 2016).
10.13# Form of Stock Option Agreement under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan
(incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on Form 8-K filed with the SEC on
October 11, 2016).
10.14# Form of Restricted Stock Unit Agreement under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan
(incorporated by reference to Exhibit 10.8 to the Registrant’s Current Report on Form 8-K filed with the SEC on October 11,
2016).
10.15# Form of Restricted Stock Agreement under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan
(incorporated by reference to Exhibit 10.9 to the Registrant’s Current Report on Form 8-K filed with the SEC on
October 11, 2016).
10.16*# Form of Performance Restricted Stock Unit Agreement under the Centennial Resource Development, Inc. 2016 Long Term
Incentive Plan.
21.1 Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 to the Registration Statement on Form S-1 of
Centennial Resource Development, Inc. (Registration No. 333-214355) filed with the SEC on October 31, 2016).
23.1* Consent of KPMG LLP.
23.2* Consent of Netherland, Sewell & Associates, Inc.
31.1* Certification of the Chief Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a).
31.2* Certification of the Chief Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a).
32.1* Certification of the Chief Executive Officer required by Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. 1350.
32.2* Certification of the Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) and 18 U.S.C. 1350.
106
99.1 Netherland, Sewell & Associates, Inc., Summary of Reserves at December 31, 2015 (incorporated by reference to Exhibit 99.2
to the Registration Statement on Form S-1 of Centennial Resource Development, Inc. (Registration No. 333-214355) filed with
the SEC on October 31, 2016).
99.2 Netherland, Sewell & Associates, Inc., Summary of Reserves at December 31, 2016 (incorporated by reference to Exhibit 99.3
to the Registrant’s Annual Report on Form 10-K filed with the SEC on March 23, 2017).
99.3* Netherland, Sewell & Associates, Inc., Summary of Reserves at December 31, 2017.
101.INS* XBRL Instance Document.
101.SCH* XBRL Taxonomy Extension Schema Document.
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB* XBRL Taxonomy Extension Label Linkbase Document.
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document.
*
Filed herewith.
# Management contract or compensatory plan or agreement.
ITEM 16. FORM 10-K SUMMARY
None.
107
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereto duly authorized.
SIGNATURES
CENTENNIAL RESOURCE DEVELOPMENT, INC.
By:
/s/ GEORGE S. GLYPHIS
George S. Glyphis
Chief Financial Officer, Treasurer and Assistant Secretary
Pursuant to the requirements of the Securities Act of 1934, this registration statement has been signed by the following
persons in the capacities and on the dates indicated.
Signature
/s/ MARK G. PAPA
Mark G. Papa
/s/ GEORGE S. GLYPHIS
George S. Glyphis
/s/ BRENT P. JENSEN
Brent P. Jensen
/s/ MAIRE A. BALDWIN
Maire A. Baldwin
/s/ KARL E. BANDTEL
Karl E. Bandtel
/s/ MATTHEW G. HYDE
Matthew G. Hyde
/s/ PIERRE F. LAPEYRE, JR.
Pierre F. Lapeyre, Jr.
/s/ DAVID M. LEUSCHEN
David M. Leuschen
/s/ JEFFREY H. TEPPER
Jeffrey H. Tepper
/s/ ROBERT M. TICHIO
Robert M. Tichio
/s/ TONY R. WEBER
Tony R. Weber
Title
Date
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
February 26, 2018
Chief Financial Officer, Treasurer and Assistant
Secretary (Principal Financial Officer)
February 26, 2018
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
February 26, 2018
Director
Director
Director
Director
Director
Director
Director
Director
108
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018