Document


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2018
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                   
Commission file number 001-37697

CENTENNIAL RESOURCE DEVELOPMENT, INC.
(Exact Name of Registrant as Specified in its Charter)
Delaware
 
47-5381253
(State of Incorporation)
 
(I.R.S. Employer Identification Number)
 
 
 
1001 Seventeenth Street, Suite 1800, Denver, Colorado
 
80202
(Address of Principal Executive Offices)
 
(Zip Code)
(720) 499-1400
(Registrant’s Telephone Number, Including Area Code)
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 such filing requirements for the past 90 days. Yes ý No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ý No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the 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 ý
 
Accelerated filer o
 
Non-accelerated filer
 o
 
Smaller reporting company o
 
Emerging growth company o
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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
As of October 31, 2018, there were 264,257,387 shares of Class A Common Stock, par value $0.0001 per share and 12,003,183 shares of Class C Common Stock, par value $0.0001 per share, outstanding.
 



TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



Table of Contents

GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this Quarterly Report on Form 10-Q, 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.

Bbls/d. Barrels 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/or location of oil or natural gas.

Dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Flush production. First yield from a flowing oil 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.

LIBOR. London Interbank Offered Rate.

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.


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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.

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, transportation and demand 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.



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GLOSSARY OF CERTAIN OTHER TERMS
The following are definitions of certain other terms that are used in this Quarterly Report on Form 10-Q:
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.
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 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, which was dissolved on June 15, 2018.
CRP. Centennial Resource Production, LLC, a Delaware limited liability company.
CRP Common Units. The units representing common membership interests in CRP.
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.
IPO. Our initial public offering of units, which closed on February 29, 2016.
NewCo. New Centennial, LLC, a Delaware limited liability company controlled by affiliates of Riverstone.
NGP Follow-On. NGP Centennial Follow-On LLC, a Delaware limited liability company.
Private Placement Warrants. Our 8,000,000 outstanding warrants for the purchase of shares of Class A Common Stock, which were purchased by our Sponsor in a private placement simultaneously with the closing of our IPO.
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.
Voting common stock. Our Class A Common Stock and Class C Common Stock.


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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (“Quarterly Report”) includes “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 Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, 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 “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Annual Report”) and the risk factors and other cautionary statements contained in our other filings with the United States Securities and Exchange Commission (“SEC”).
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; 
the marketing and transportation of our 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 Quarterly Report that are not historical.
All forward-looking statements, expressed or implied, are made only as of the date of this Quarterly Report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including but not limited to those risks described under “Item 1A. Risk Factors” in our 2017 Annual Report. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make.
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.
Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied by the forward-looking statements.

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All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this Quarterly Report.



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PART I. FINANCIAL INFORMATION
Item 1.    Financial Statements
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED BALANCE SHEETS (unaudited)
(in thousands, except share and per share amounts
 
September 30, 2018
 
December 31, 2017
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
58,922

 
$
117,315

Accounts receivable, net
88,817

 
78,786

Derivative instruments
3,871

 
433

Prepaid and other current assets
14,277

 
6,051

Total current assets
165,887

 
202,585

Property and Equipment
 
 
 
Oil and natural gas properties, successful efforts method
 
 
 
Unproved properties
1,801,965

 
1,952,680

Proved properties
2,402,331

 
1,602,002

Accumulated depreciation, depletion and amortization
(395,675
)
 
(173,906)

Total oil and natural gas properties, net
3,808,621

 
3,380,776

Other property and equipment, net
7,828

 
5,465

Total property and equipment, net
3,816,449

 
3,386,241

Noncurrent assets
 
 
 
Derivative instruments

 
662

Other noncurrent assets
35,036

 
27,081

TOTAL ASSETS
$
4,017,372

 
$
3,616,569

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable and accrued expenses
$
210,608

 
$
199,533

Derivative instruments

 
240

Other current liabilities
655

 

Total current liabilities
211,263

 
199,773

Noncurrent liabilities
 
 
 
Long-term debt, net
531,390

 
390,764

Asset retirement obligations
13,156

 
12,161

Deferred tax liability
53,380

 
9,899

Derivative instruments
2,437

 

Other long-term liabilities
540

 

Total liabilities
812,166

 
612,597

Commitments and contingencies (Note 12)


 


Shareholders’ equity
 
 
 
Preferred stock, $0.0001 par value, 1,000,000 shares authorized:
 
 
 
Series A: 1 share issued and outstanding

 

Common stock, $0.0001 par value, 620,000,000 shares authorized:
 
 
 
Class A: 265,771,082 shares issued and 264,214,812 shares outstanding at September 30, 2018 and 261,337,636 shares issued and 260,327,920 shares outstanding at December 31, 2017
27

 
26

Class C (Convertible): 12,003,183 and 15,661,338 shares issued and outstanding at September 30, 2018 and December 31, 2017, respectively
1

 
2

Additional paid-in capital
2,827,756

 
2,767,558

Retained earnings
235,558

 
66,639

Total shareholders’ equity
3,063,342

 
2,834,225

Noncontrolling interest
141,864

 
169,747

Total equity
3,205,206

 
3,003,972

TOTAL LIABILITIES AND EQUITY
$
4,017,372

 
$
3,616,569

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

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CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)

For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,

2018

2017

2018

2017
Operating revenues











Oil and gas sales
$
234,880


$
111,611


$
668,541


$
263,772

Operating expenses











Lease operating expenses
23,706


11,373


59,164


26,924

Severance and ad valorem taxes
14,410


6,448


42,791


14,358

Gathering, processing and transportation expenses
16,090


9,925


45,214


22,572

Depreciation, depletion and amortization
83,423


42,387


224,379


102,847

Impairment and abandonment expenses
8,612




10,396


(29
)
Exploration expense
2,712


1,622


8,026


4,092

General and administrative expenses
16,561


13,311


44,667


36,017

Total operating expenses
165,514


85,066


434,637


206,781













Income from operations
69,366


26,545


233,904


56,991













Other income (expense)











Gain (loss) on sale of oil and natural gas properties
52


(141
)

(74
)

7,216

Interest expense
(6,534
)

(1,015
)

(18,138
)

(2,132
)
Net gain (loss) on derivative instruments
(9,571
)

(896
)

14,969


5,392

Other income (expense)
13




(4
)


Other income (expense)
(16,040
)

(2,052
)

(3,247
)

10,476













Income before income taxes
53,326


24,493


230,657


67,467

Income tax expense
(11,652
)

(8,233
)

(50,729
)

(17,302
)
Net income
41,674


16,260


179,928


50,165

Less: Net income attributable to noncontrolling interest
2,386


1,813


11,009


5,133

Net income attributable to Class A Common Stock
$
39,288


$
14,447


$
168,919


$
45,032













Income per share of Class A Common Stock:











Basic
$
0.15


$
0.06


$
0.64


$
0.20

Diluted
$
0.15


$
0.06


$
0.63


$
0.19

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


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CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
 
For the Nine Months Ended September 30,
 
2018

2017
Cash flows from operating activities:
 
 
 
Net income
$
179,928

 
$
50,165

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
224,379

 
102,847

Stock-based compensation expense
14,329

 
9,420

Undeveloped leasehold abandonment expense
10,396

 
(29
)
Exploratory dry hole cost
395

 

Deferred tax expense
50,729

 
17,302

(Gain) loss on sale of oil and natural gas properties
74

 
(7,216
)
Non-cash mark-to-market derivative gain
(579
)
 
(5,126
)
Amortization of debt issuance costs
1,258

 
348

Changes in operating assets and liabilities:
 
 
 
(Increase) decrease in accounts receivable
(18,327
)
 
(28,172
)
(Increase) decrease in prepaid and other assets
(52
)
 
(12,890
)
Increase (decrease) in accounts payable and other liabilities
32,165

 
10,501

Net cash provided by operating activities
494,695

 
137,150

Cash flows from investing activities:
 
 
 
Acquisitions of oil and natural gas properties
(114,870
)
 
(419,471
)
Drilling and development capital expenditures
(723,100
)
 
(354,515
)
Purchases of other property and equipment
(4,409
)
 
(3,482
)
Proceeds from sales of oil and natural gas properties
147,413

 
10,714

Net cash used in investing activities
(694,966
)
 
(766,754
)
Cash flows from financing activities:
 
 
 
Issuance of Class A common shares

 
340,750

Underwriters discount and offering costs

 
(7,233
)
Proceeds from revolving credit facility
295,000

 
190,000

Repayment of revolving credit facility
(155,000
)
 
(25,000
)
Proceeds from stock options exercised
847

 

Restricted stock used for tax withholdings
(1,119
)
 

Debt issuance costs
(4,217
)
 
(415
)
Net cash provided by financing activities
135,511

 
498,102

Net decrease in cash and cash equivalents and restricted cash
(64,760
)
 
(131,502
)
Cash and cash equivalents and restricted cash, beginning of period
125,915

 
134,083

Cash, cash equivalents and restricted cash, end of period
$
61,155

 
$
2,581

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

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Supplemental cash flow information and non-cash activity (in thousands):
 
For the Nine Months Ended September 30,
 
2018

2017
Supplemental cash flow information
 
 
 
Cash paid for interest
$
15,587

 
$
1,915

Supplemental non-cash activity
 
 
 
Accrued capital expenditures included in accounts payable and accrued expenses
$
97,844

 
$
102,152

Asset retirement obligations incurred, including revisions to estimates
1,040

 
1,016

Reconciliation of cash, cash equivalents and restricted cash presented on the Consolidated Statements of Cash Flows:
 
For the Nine Months Ended September 30,
 
2018
 
2017
Cash and cash equivalents
$
58,922

 
$
2,581

Restricted cash(1)
2,233

 

Total cash, cash equivalents and restricted cash
$
61,155

 
$
2,581

 
(1) 
Included in Prepaid and other current assets line item on the Consolidated Balance Sheets



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CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)
(in thousands)

 
Common Stock
 
Preferred Stock
 
 
 
 
 
 
 
 
 
 
 
Class A
 
Class C
 
Series A
 
Series B
 
Additional Paid-In Capital
 
Retained Earnings (Accumulated Deficit)
 
Total Shareholder's Equity
 
Non-controlling Interest
 
Total Equity
 
Shares
 
Amount
 
Shares
 
Amount
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
 
 
Balance at December 31, 2016
201,092

 
$
20

 
19,156

 
$
2

 

 
$

 
104

 
$

 
$
2,364,049

 
$
(8,929
)
 
$
2,355,142

 
$
197,793

 
$
2,552,935

Warrants exercised
6,236

 
1

 

 

 

 

 

 

 
(1
)
 

 

 

 

Restricted stock issued
841

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock forfeited
(9
)
 

 

 

 

 

 

 

 

 

 

 

 

Conversion of Series B preferred shares to Class A common shares
26,100

 
3

 

 

 

 

 
(104
)
 

 
(3
)
 

 

 

 

Sale of unregistered Class A common shares
23,500

 
2

 

 

 

 

 

 

 
340,748

 

 
340,750

 

 
340,750

Underwriters' discount and offering expense

 

 

 

 

 

 

 

 
(7,233
)
 

 
(7,233
)
 

 
(7,233
)
Stock-based compensation

 

 

 

 

 

 

 

 
9,420

 

 
9,420

 

 
9,420

Change in equity due to issuance of shares by Centennial Resource Production, LLC

 

 

 

 

 

 

 

 
(2,682
)
 

 
(2,682
)
 
2,682

 

Net income

 

 

 

 

 

 

 

 

 
45,032

 
45,032

 
5,133

 
50,165

Balance at September 30, 2017
257,760

 
$
26

 
19,156

 
$
2

 

 
$

 

 
$

 
$
2,704,298

 
$
36,103

 
$
2,740,429

 
$
205,608

 
$
2,946,037

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2017
261,338

 
$
26

 
15,661

 
$
2

 

 
$

 

 
$

 
$
2,767,558

 
$
66,639

 
$
2,834,225

 
$
169,747

 
$
3,003,972

Restricted stock issued
919

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock forfeited
(136
)
 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock used for tax withholding
(60
)
 

 

 

 

 

 

 

 
(1,119
)
 

 
(1,119
)
 

 
(1,119
)
Option Exercises
52

 

 

 

 

 

 

 

 
847

 

 
847

 

 
847

Stock-based compensation

 

 

 

 

 

 

 

 
14,329

 

 
14,329

 

 
14,329

Conversion of common shares from Class C to Class A, net of tax
3,658

 
1

 
(3,658
)
 
(1
)
 

 

 

 

 
46,141

 

 
46,141

 
(38,892
)
 
7,249

Net income

 

 

 

 

 

 

 

 

 
168,919

 
168,919

 
11,009

 
179,928

Balance at September 30, 2018
265,771

 
$
27

 
12,003

 
$
1

 

 
$

 

 
$

 
$
2,827,756

 
$
235,558

 
$
3,063,342

 
$
141,864

 
$
3,205,206



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


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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1—Basis of Presentation
Description of Business
Centennial Resource Development, Inc. 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 primarily of large, contiguous acreage blocks primarily in Reeves County in West Texas and Lea County in New Mexico. Unless otherwise specified or the context otherwise requires, all references in these notes to “Centennial” or the “Company” are to Centennial Resource Development, Inc. and its consolidated subsidiary, Centennial Resource Production, LLC (“CRP”).
Principles of Consolidation and Basis of Presentation
The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and the rules and regulations of the United States Securities and Exchange Commission (“SEC”) for interim financial reporting. Accordingly, certain disclosures normally included in an Annual Report on Form 10-K have been omitted. The consolidated financial statements and related notes included in this Quarterly Report should be read in conjunction with the Company’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the period ended December 31, 2017 (the “2017 Annual Report”). Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company’s 2017 Annual Report.
In the opinion of management, all normal, recurring adjustments and accruals considered necessary to present fairly, in all material respects, the Company’s interim financial results have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year.
The consolidated financial statements include the accounts of the Company and its majority owned subsidiary CRP, and CRP’s wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.
Noncontrolling interest represents third-party ownership in the Company’s consolidated subsidiary, and it is presented as a component of equity. See Note 9—Shareholders' Equity and Noncontrolling Interest for further discussion of noncontrolling interest.
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 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 revenues and related receivables; (vii) accrued liabilities; (viii) valuation of derivative instruments; and (ix) deferred income taxes.
Income Taxes
Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to the Company’s year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent and temporary differences and the likelihood of recovering deferred tax assets generated in the current year. The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained, additional information becomes known or as the tax environment changes.


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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Recently Issued Accounting Standards
In August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement, which updates the disclosure requirements for fair value measurements in Accounting Standard Codification (“ASC”) Topic 820, Fair Value Measurement (“ASC Topic 820”). Certain disclosure requirements under ASC Topic 820 were removed, modified or added in order to improve the effectiveness of the fair value note to the financial statement. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2019, including interim periods within those fiscal years. An entity is permitted to early adopt any removed or modified disclosures and delay adoption of the additional disclosures until the effective date. The Company is currently assessing the impact of this update on the Company's consolidated financial statements.
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 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. The Company adopted ASU 2016-15 in the first quarter of 2018. As a result of adoption, there were no changes to the presentation of cash flow activities in the statement of cash flows for the nine months ended September 30, 2018.
In February 2016, the FASB issued ASU 2016-02, Leases, which created ASC Topic 842, Leases (“ASC Topic 842”), superseding current lease requirements under ASC Topic 840, Leases. Subsequently in 2018, the FASB issued various ASUs which provide a practical expedient for the evaluation of existing land easement agreements, optionality in the adoption transition method, and additional implementation guidance. ASC Topic 842 and its related amendments apply to any entity that enters into a lease, with some specified scope exemptions. Under ASC Topic 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. ASC Topic 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. The standard permits retrospective application using either of the following methodologies: (i) application of the new standard at the earliest presented period or (ii) application of the new standard at the adoption date with a cumulative-effect adjustment recognized to retained earnings. The Company will adopt this guidance as of January 1, 2019, the effective date, and plans to recognize a cumulative-effect adjustment at the time of adoption. Although the Company is still in the process of evaluating the effect of adopting ASC Topic 842 and its related amendments, the adoption is expected to result in the recognition of assets and liabilities on its Consolidated Balance Sheet for current operating leases such as drilling rig contracts and office rental agreements. The Company is continuing to evaluate existing arrangements to determine if they qualify for lease accounting under ASC Topic 842.
In May 2014, the FASB issued ASU 2014-09, which created ASC Topic 606, Revenue from Contracts with Customers (“ASC Topic 606”), superseding 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 ASC Topic 606 and provided additional implementation guidance. ASC Topic 606 provides companies with a single model for use in accounting for revenue arising from contracts with customers. 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. ASC Topic 606 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard permits 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 completed its review of the impact of the new standard on its significant contracts and concluded that there was not a material impact to the presentation of revenues or expenses as a result of the adoption of this standard. Refer to Note 13—Revenues for additional disclosures required by the new standard.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Note 2—Property Acquisitions and Divestiture
Acquisition
On February 8, 2018, the Company completed the acquisition of approximately 4,000 undeveloped net acres, as well as certain producing properties, in Lea County, New Mexico for an unadjusted purchase price of $94.7 million. The operated acreage position contains an approximate 92% average working interest and is largely contiguous to Centennial’s existing positions in the northern Delaware Basin. Upon signing the purchase and sale agreement, the Company placed $8.6 million of cash in escrow accounts on December 21, 2017, and such deposits were applied as a payment against 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 in the Consolidated Balance Sheet as of December 31, 2017.
The acquisition was recorded as an asset acquisition under ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. Accordingly, the purchase consideration has been allocated to the oil and natural gas properties based on their relative fair values measured as of the acquisition date. After settlement statement adjustments of $0.2 million, the Company paid a net purchase price of $94.5 million. On a relative fair value basis, $80.7 million was allocated to unproved properties and $13.8 million to proved properties. Transaction costs incurred and capitalized as of September 30, 2018, amounted to $0.2 million and mainly consisted of advisory and legal fees.
Disposition
On March 2, 2018, the Company completed the sale of approximately 8,600 undeveloped net acres and 12 gross producing wells located in Reeves County, Texas for a total unadjusted sales price of $140.7 million. The divested acreage represents a largely non-operated position (32% average working interest) on the western portion of Centennial’s position in Reeves County. There was no gain or loss recognized as a result of this divestiture, which constituted a partial sale of oil and gas properties in accordance with ASC 932, Extractive Activities - Oil and Gas. The Company used the net proceeds from the sale to fund the 2018 acquisition discussed above and for general corporate purposes.
Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
(in thousands)
September 30, 2018

December 31, 2017
Accrued oil and gas sales receivable, net
$
68,128


$
52,891

Joint interest billings
20,093


25,256

Receivables for divestitures
416



Other
180


639

Accounts receivable, net
$
88,817


$
78,786

Accounts payable and accrued expenses are comprised of the following:
(in thousands)
September 30, 2018
 
December 31, 2017
Accounts payable
$
27,252

 
$
64,004

Accrued capital expenditures
107,786

 
90,511

Revenues payable
47,995

 
23,390

Accrued interest
5,310

 
1,936

Accrued employee compensation and benefits
7,338

 
8,350

Accrued expenses and other
14,927

 
11,342

Accounts payable and accrued expenses
$
210,608

 
$
199,533


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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Note 4—Long-Term Debt
Credit Agreement
On May 4, 2018, CRP, the Company’s consolidated subsidiary, entered into an amended and restated credit agreement with a syndicate of banks that as of September 30, 2018, had a borrowing base of $800.0 million and elected commitments of $600.0 million. The credit agreement provides for a five-year secured revolving credit facility, maturing on May 4, 2023. As of September 30, 2018, the Company had $140.0 million borrowings outstanding and $459.1 million in available borrowing capacity, which was net of $0.9 million in letters of credit outstanding.
The amount available to be borrowed under the Company’s credit agreement is equal to the lesser of (i) the borrowing base, (ii) aggregate elected commitments, or (iii) $1.5 billion. The borrowing base is redetermined semi-annually each April 1 and October 1 by the lenders in their sole discretion. It also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the quantities of CRP’s proved oil and natural gas reserves, estimated cash flows from these reserves, and the Company’s commodity hedge positions. Upon a redetermination of the borrowing base, if actual borrowings exceed the revised borrowing capacity, CRP could be required to immediately repay a portion of its debt outstanding under the credit agreement. In connection with the October 2018 semi-annual credit facility redetermination, the borrowing base under the revolving credit facility was increased from $800.0 million to $1.0 billion and the lenders increased their aggregate elected commitments from $600.0 million to $800.0 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 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” later in this Quarterly 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 May 4, 2023, 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: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make or declare dividends; (v) enter into commodity hedges exceeding a specified percentage of the Company’s expected production; (vi) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (vii) incur liens; (viii) sell assets; and (ix) 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 derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the credit agreement and non-cash derivative liabilities), 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 September 30, 2018 and through the filing of this Quarterly 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 a 144A private placement that resulted in net proceeds to CRP of $391.0 million, after deducting $9.0 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 any accrued and unpaid interest 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, and any accrued and unpaid interest as of 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

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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


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 (and, in some cases, followed by a ratings decline), 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 these covenants as of September 30, 2018 and through the filing of this Quarterly 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. In addition, 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.
Debt issuance costs netted against the principal balance of the Senior Notes amounted to $8.6 million as of September 30, 2018 and $9.2 million as of December 31, 2017.
Note 5—Asset Retirement Obligations
The following table summarizes the changes in the Company’s asset retirement obligations (“ARO”) for the nine months ended September 30, 2018 (in thousands):
Asset retirement obligations at January 1, 2018
$
12,161

Liabilities acquired
42

Liabilities incurred
1,051

Liabilities divested and settled
(672
)
Accretion expense
585

Revisions to estimated cash flows
(11
)
Asset retirement obligations at September 30, 2018
$
13,156

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 gas property balance.
Note 6—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 September 30, 2018, the Company had 9,795,116 shares of Class A Common Stock available for future grants. The LTIP provides for grants 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 both General and administrative expenses and Exploration expense in the Consolidated Statements of Operations. The expense amounts in the table below may not be representative of future expense amounts to be recognized as the value of future awards may vary from historical award 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.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


The following table summarizes stock-based compensation expense recognized for the periods presented:
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
(in thousands)
2018
 
2017
 
2018
 
2017
Restricted stock awards
$
2,393

 
$
1,490

 
$
6,157

 
$
3,364

Stock option awards
2,337

 
2,104

 
6,853

 
5,825

Performance stock units
611

 
231

 
1,319

 
231

Total stock-based compensation expense
$
5,341

 
$
3,825

 
$
14,329

 
$
9,420

Restricted Stock
The following table provides information about restricted stock awards outstanding during the nine months ended September 30, 2018:
 
Awards
 
Weighted Average Grant Date Fair Value
Unvested balance as of December 31, 2017
1,009,716

 
$
17.64

Granted
919,306

 
18.38

Vested
(236,701
)
 
16.92

Forfeited
(136,051
)
 
17.70

Unvested balance as of September 30, 2018
1,556,270

 
18.18

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 fair value of the award, and such costs are recognized ratably over the applicable vesting period. The weighted average grant-date fair value for restricted stock awards granted was $18.38 per share and $17.21 per share for the nine months ended September 30, 2018 and 2017, respectively. The total fair value of restricted stock awards that vested during the nine months ended September 30, 2018 was $4.4 million, and no awards vested during the nine months ended September 30, 2017. Unrecognized compensation cost related to restricted shares that were unvested as of September 30, 2018 was $23.5 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 vest ratably over a three-year service period. The exercise price for an option granted under the LTIP is the closing price of the Company’s Class A Common Stock as reported on the 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 weighted average asset volatility of the Company and identified set of comparable companies. Expected term is based on the simplified method and is estimated as the mid-point between 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 nine months ended September 30, 2018 and 2017:

For the Nine Months Ended September 30,

2018

2017
Weighted average grant-date fair value per share
$
7.74


$
7.15

Expected term (in years)
6


6

Expected stock volatility
41.4
%

38.1
%
Dividend yield
%

%
Risk-free interest rate
2.6
%

2.0
%

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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


The following table provides information about stock option awards outstanding during the nine months ended September 30, 2018:
 
Options
 
Weighted Average Exercise Price
 
Weighted Average Remaining Term
(in years)
 
Aggregate Intrinsic Value
(in thousands)
Outstanding as of December 31, 2017
4,290,001

 
$
16.15

 
 
 
 
Granted
358,500

 
17.78

 
 
 
 
Exercised
(52,331
)
 
16.18

 
 
 
$
192

Forfeited
(225,337
)
 
15.80

 
 
 
 
Expired
(4,166
)
 
16.60

 
 
 
 
Outstanding as of September 30, 2018
4,366,667

 
16.30

 
8.4
 
24,218

Exercisable as of September 30, 2018
1,223,811

 
15.98

 
8.2
 
7,179

The total fair value of stock options that vested during the nine months ended September 30, 2018 was $3.7 million, and no awards vested during the nine months ended September 30, 2017. As of September 30, 2018, there was $13.5 million of unrecognized compensation cost related to unvested stock options, which the Company expects to recognize on a pro-rata basis over a weighted average period of 1.6 years.
Performance Stock Units
The Company grants to certain 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 our 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 nine months ended September 30, 2018 and 2017:

For the Nine Months Ended September 30,

2018
 
2017
Weighted average grant-date fair value per share
$
22.35

 
$
21.53

Number of simulations
1,000,000

 
1,000,000

Expected stock volatility
40.2
%
 
41.6
%
Dividend yield
%
 
%
Risk-free interest rate
2.8
%
 
1.5
%

The following table provides information about performance stock units outstanding during the nine months ended September 30, 2018:


Awards
 
Weighted Average Grant-Date Fair Value
Outstanding as of December 31, 2017
193,391

 
$
21.53

Vested

 

Granted
193,068

 
22.35

Forfeited

 

Outstanding as of September 30, 2018
386,459

 
21.94


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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


As of September 30, 2018, there was $6.6 million of unrecognized compensation cost related to performance stock units that were unvested, which the Company expects to recognize on a pro-rata basis over a weighted average period of 2.4 years.
Note 7—Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations and may use 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, 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 as well as basis swaps to hedge the difference between the index price and a local index price. All transactions are settled in cash with one party paying the other for the resulting difference in price multiplied by the contract volume.
The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of September 30, 2018:

Period

Volume (Bbls)

Volume (Bbls/d)

Weighted Average Differential ($/Bbl) (1)
Crude oil basis swaps
October 2018 - December 2018

828,000


9,000


$
(2.38
)

January 2019 - March 2019

540,000


6,000


(5.34
)

April 2019 - June 2019

91,000


1,000


(10.00
)

July 2019 - September 2019

1,380,000


15,000


(9.03
)

October 2019 - December 2019

920,000


10,000


(4.24
)
 
(1) 
The oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during the relevant calculation period.

Period

Volume (MMBtu)

Volume (MMBtu/d)

Weighted Average Fixed Price ($/MMBtu) (1)
Natural Gas Swaps - Henry Hub
January 2019 - December 2019

10,950,000


30,000


$
2.78

Natural Gas Swaps - West Texas WAHA
January 2019 - December 2019

5,475,000


15,000


1.61










Period

Volume (MMBtu)

Volume (MMBtu/d)

Weighted Average Differential ($/MMBtu) (2)
Natural gas basis swaps
October 2018 - December 2018

460,000


5,000


$
(0.43
)

January 2019 - December 2019

12,775,000


35,000


(1.31
)
 
(1) 
The natural gas swap contracts are settled based on either i) the NYMEX Henry Hub price or ii) the Inside FERC West Texas WAHA price of natural gas as of the specified settlement date, as applicable.
(2) 
The natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas during the relevant calculation period.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


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 in the Consolidated Balance Sheets, other than derivative instruments that meet the “normal purchase normal sale” exclusion, and any fair value gains and losses are recognized in current period earnings.
The following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for the periods presented:
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
(in thousands)
2018
 
2017
 
2018
 
2017
Net gain (loss) on derivative instruments
$
(9,571
)
 
$
(896
)
 
$
14,969

 
$
5,392

Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives 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 table below summarizes the fair value amounts and the classification in the Consolidated Balance Sheets of the Company’s derivative contracts outstanding at the respective balance sheet dates. Refer to Note 8—Fair Value Measurements for details of the gross and net derivative assets, liabilities and offset amounts as presented in the Consolidated Balance Sheets.
 
 
 
Gross Asset/Liability Amounts
(in thousands)
Balance Sheet Classification
 
September 30, 2018
 
December 31, 2017
Derivative Assets
 
 
 
 
 
Derivative instruments
Current assets
 
$
10,184

 
$
720

Derivative instruments
Noncurrent assets
 
418

 
662

Total derivative assets
 
 
$
10,602

 
$
1,382

Derivative Liabilities
 
 
 
 
 
Derivative instruments
Current liabilities
 
$
6,313

 
$
527

Derivative instruments
Noncurrent liabilities
 
2,855

 

Total derivative liabilities
 
 
$
9,168

 
$
527

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 the Company 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 lender under CRP’s credit facility as referenced above.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Note 8—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 presents the Company’s netted asset or liability positions that have been measured at fair value and where they have been classified within the fair value hierarchy as of September 30, 2018 and December 31, 2017:
 
Fair Value Measurements
 
Gross Amounts of Assets and Liabilities
 
Netting Adjustments(1)
 
Net Amounts Presented on the Balance Sheets
 
Level 1
 
Level 2
 
Level 3
 
 
(in thousands)
September 30, 2018
Financial assets
 
 
 
 
 
 
 
 
 
Commodity derivative asset - current
$

 
$
10,184

 
$

 
$
(6,313
)
 
$
3,871

Commodity derivative asset - noncurrent

 
418

 

 
(418
)
 

Total financial assets
$

 
$
10,602

 
$

 
$
(6,731
)
 
$
3,871

 
 
 
 
 
 
 
 
 
 
Financial liabilities
 
 
 
 
 
 
 
 
 
Commodity derivative liability - current
$

 
$
6,313

 
$

 
$
(6,313
)
 
$

Commodity derivative liability - noncurrent

 
2,855

 

 
(418
)
 
2,437

Total financial liabilities
$

 
$
9,168

 
$

 
$
(6,731
)
 
$
2,437

 
 
 
 
 
 
 
 
 
 
 
December 31, 2017
Financial Assets
 
 
 
 
 
 
 
 
 
Commodity derivative asset - current
$

 
$
720

 
$

 
$
(287
)
 
$
433

Commodity derivative asset - noncurrent

 
662

 

 

 
662

Total financial assets
$

 
$
1,382

 
$

 
$
(287
)
 
$
1,095

 
 
 
 
 
 
 
 
 
 
Financial liabilities
 
 
 
 
 
 
 
 
 
Commodity derivative liability - current
$

 
$
527

 
$

 
$
(287
)
 
$
240

 
(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.
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.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


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 natural gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation. Refer to Note 2—Property Acquisitions and Divestiture for additional information on the fair value of assets acquired.
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 5—Asset Retirement Obligations for additional information on the Company’s ARO.
Other Financial Instruments
The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate their fair values 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, if any, 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 September 30, 2018 and December 31, 2017, the fair value of the Senior Notes was $399.0 million and $407.5 million, respectively, which were determined using quoted market prices for this same debt security, a Level 1 classification in the fair value hierarchy.
Note 9—Shareholders' Equity and Noncontrolling Interest
Shareholders’ Equity
On March 7, 2018, Silver Run Sponsor, LLC (“Silver Run Sponsor”), the Riverstone Purchasers and the Centennial Contributors 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 3,347,647 shares of CRP Common Units (and corresponding shares of Class C Common Stock) were converted to shares of Class A Common Stock on a one-to-one basis. A tax benefit of $6.7 million was recorded in equity as a result of the conversion of shares from the noncontrolling interest owner.
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 represented 10.9% of the ownership in CRP. The noncontrolling interest percentage is affected by various equity transactions such as CRP Common Unit and Class C Common Stock exchanges and Class A Common Stock activities.
As of September 30, 2018, the noncontrolling interest ownership of CRP decreased to 4.3% from 5.7% as of December 31, 2017. The decrease was mainly the result of the exchange of CRP Common Units (and corresponding shares of Class C Common Stock) for Class A Common Stock.
The Company consolidates the financial position, results of operations and cash flows of CRP and reflects 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.

23

Table of Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Note 10—Earnings Per Share
Basic earnings per share (“EPS”) is calculated by dividing net income available to Class A Common Stock by the weighted average shares of Class A Common Stock outstanding during each period. Diluted EPS is calculated by dividing adjusted net income available to Class A Common Stock by the weighted average shares of diluted Class A Common Stock 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.
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.
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. The Company’s shares of Series B Preferred Stock had a non-forfeitable right to participate in distributions with common stockholders on a pro-rata, as-converted basis. All of Company’s shares of Series B Preferred Stock were converted into shares of Class A Common Stock on May 25, 2017 in accordance with their terms. As such, the Company no longer has any participating securities as of September 30, 2018 and 2017.
The following table reflects the allocation of net income to common shareholders and EPS computations for the periods indicated based on a weighted average number of common stock outstanding for the period:

For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
(in thousands, except per share data)
2018
 
2017

2018

2017
Net income attributable to Class A Common Stock
$
39,288


$
14,447


$
168,919


$
45,032

Add: Income from conversion of Class C Common Stock
1,717


1,193




3,196

Adjusted net income attributable to Class A Common Stock
41,005

 
15,640

 
168,919

 
48,228

 
 
 
 
 
 
 
 
Basic net earnings per share of Class A Common Stock
$
0.15

 
$
0.06

 
$
0.64

 
$
0.20

Diluted net earnings per share of Class A Common Stock
$
0.15

 
$
0.06

 
$
0.63

 
$
0.19

 
 
 
 
 
 
 
 
Basic weighted average shares of Class A Common Stock outstanding
263,959

 
223,622

 
263,029

 
227,557

Add: Dilutive effects of equity awards
3,766

 
2,598

 
3,625

 
4,481

Add: Dilutive effects of conversion
12,189

 
19,156

 

 
19,156

Diluted weighted average shares of Class A Common Stock outstanding
279,914

 
245,376

 
266,654

 
251,194

For the three and nine months ended September 30, 2018 and 2017, the following shares were excluded from the diluted earnings per share calculation as their impacts were anti-dilutive:

For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
(in thousands)
2018
 
2017
 
2018
 
2017
Out-of-the-money stock options
142

 
1,501

 
318

 
1,046

Weighted average shares of Class C Common Stock

 

 
13,056

 

Performance stock units

 

 
52

 



24

Table of Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Note 11—Transactions with Related Parties
The Company obtains services related to its drilling and completion activities from related parties from time to time. The Company believes that the terms of the arrangements with these related parties are no less favorable to either party than those held with unaffiliated parties. The following table summarizes the costs incurred for such services which were either included as part of oil and natural gas properties in the Consolidated Balance Sheet or as lease operating expense in the Consolidated Statements of Operations, as well as the related payables outstanding as of the balance sheet dates:
 
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
(in thousands)
 
2018
 
2017
 
2018
 
2017
Costs of goods/services provided
 
 
 
 
 
 
 
 
Liberty Oilfield Services, LLC(1)
 
$

 
$
30,434

 
$

 
$
70,616

Schlumberger Limited and affiliates(2)
 
2,872

 

 
2,872

 

Oil States International, Inc.(3)
 
647

 
2,443

 
5,047

 
6,375

(in thousands)
September 30, 2018
 
December 31, 2017
Accounts payable and accrued expenses
 
 
 
Schlumberger Limited and affiliates(2)
$
1,290

 
$

Oil States International, Inc.(3)

 
1,518

 
(1)
This entity is a Riverstone affiliate. Riverstone and its affiliates, beneficially own more than 10% equity interest in the Company and are therefore considered related parties.
(2) 
On August 8, 2018, Mark G. Papa, the Company’s Chief Executive Officer and Chairman of the Board, was elected as a director of the Board of Schlumberger Limited (“Schlumberger”), an oilfield services company. As a result, Schlumberger and its affiliates are considered related parties of the Company. Any goods/services acquired from Schlumberger and its affiliates on or after August 8, 2018, are classified as related party transactions.
(3) 
Mark G. Papa served as a director and Chairman of the Board of Oil States International, Inc. (“Oil States”), an energy services company. Effective August 7, 2018, Mr. Papa resigned from Oil States’ Board and they were no longer a related party of the Company. Any goods/services acquired on or after August 7, 2018 from Oil States are no longer classified as related party transactions.
Note 12—Commitments and Contingencies
Commitments
In 2018, the Company entered into various natural gas transportation agreements whereby it is required to deliver approximately 491 million MMBtu, in aggregate, over a term ranging from one to four years or else pay for any volume deficiencies. These delivery commitments are tied to the Company’s natural gas production, and the aggregate financial obligation under these contracts is $38.4 million, representing the minimum commitments pursuant to the terms of these agreements as of September 30, 2018. Actual expenditures under these contracts may exceed this minimum commitment amount. The following table summarizes the natural gas volumes the Company is required to deliver by period under these agreements as well as its existing natural gas transportation agreements:
Period

Total Volume Commitments (MMBtu) (1)

Volume (MMBtu/d) (1)
October 2018 - December 2018

16,200,000


176,000

January 2019 - December 2019

116,800,000


320,000

January 2020 - December 2020

194,800,000


533,600

January 2021 - December 2021

158,100,000


433,200

January 2022 - October 2022

19,700,000


64,800

Total

505,600,000



 
(1)
The amounts reflected within this table are the total gross volumes the Company is required to deliver per the agreements. These volumetric quantities are therefore not comparable to the Company’s net production presented in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation as the amounts therein are reflected net of all royalties, overriding royalties and production due to others.

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Table of Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


In May 2018, the Company entered into a three-year supply agreement to purchase frac sand from an in-basin sand mine in West Texas. Under the terms of the agreement, the Company is obligated to purchase a minimum volume of sand at a fixed sales price. The aggregate financial obligation under this contract is $23.8 million, which represents the minimum commitments pursuant to the terms of the agreement as of September 30, 2018. Actual expenditures under this contract may exceed this minimum commitment amount.

Delivery Commitments
In August 2018, the Company entered into two firm crude oil sales agreements with large integrated oil companies. Utilizing these companies’ existing transport capacity out of the Permian Basin, the agreements provide for firm gross sales ranging from approximately 40,000 to 105,000 Bbls/d in aggregate over the next six years. These amounts represent the total gross volumes the Company is required to deliver per the agreements, which are not comparable to the Company’s net production presented in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation as amounts therein are reflected net of all royalties, overriding royalties and production due to others. These sales agreements require the Company to physically deliver the aforementioned volumes of crude oil over the contractual terms of the agreements. The Company believes its current production and reserves are sufficient to fulfill these delivery commitments, but if the physical delivery commitments are not met, a financial obligation may arise. However, the aggregate amount of any such potential financial obligation under these contracts is not determinable since the amount and timing of any volumetric shortfalls, as well as the difference between the prevailing market price and contract price at such time, cannot be predicted with accuracy.
The Company routinely enters into or extends operating agreements, office and equipment leases, drilling and completion rig contracts, among others, in the ordinary course of business. Other than those discussed above, there have been no material, non-routine changes in commitments during the nine months ended September 30, 2018. Please refer to Note 13—Commitments and Contingencies included in Part II, Item 8 in the Company’s 2017 Annual Report.
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 a contingent liability to be recognized as of the date of these consolidated financial statements.
Note 13—Revenues
Revenue from Contracts with Customers
Sales of crude oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials. As a result, the price of oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies both globally (in the case of crude oil) and locally.
Oil and gas revenues presented within the Consolidated Statements of Operations relate to the sale of oil, natural gas and NGLs as shown below:
 
For the Three Months Ended September 30,
 
For the Nine Months Ended September 30,
 
2018
 
2017
 
2018

2017
Operating revenues (in thousands):
 
 
 
 
 
 
 
Oil sales
$
184,510

 
$
87,286

 
$
533,507

 
$
204,702

Natural gas sales
14,311

 
12,852

 
46,612

 
33,226

NGL sales
36,059

 
11,473

 
88,422

 
25,844

Oil and gas sales
$
234,880

 
$
111,611

 
$
668,541

 
$
263,772


26

Table of Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Oil sales
The Company’s crude oil sales contracts are generally structured whereby oil is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. This delivery point is usually at the wellhead or at the inlet of a transportation pipeline. Revenue is recognized when control transfers to the purchaser at the delivery point based on the net price received from the purchaser. Any downstream transportation costs incurred by crude purchasers are reflected as a net reduction to oil sales revenues.
Natural gas and NGL sales
Under certain natural gas processing contracts, liquids rich natural gas is delivered to a midstream processing entity at the inlet of the gas plant processing system. The midstream processing entity gathers and processes the natural gas and remits proceeds to Centennial for the resulting sales of NGLs and residue gas. For these contracts, the Company evaluates when control is transferred and revenue should be recognized. Where the Company has concluded that control transfers at the tailgate of the processing facility, fees incurred prior to transfer of control are presented as gathering, processing and transportation expenses (“GP&T”) within the Consolidated Statements of Operations, rather than as a net reduction to natural gas and NGL sales.
In the Company’s other natural gas processing agreements, it has the election to take its residue gas ‘in-kind’ at the tailgate of the midstream processing plant and then subsequently market the product. For these contracts, the Company recognizes revenue when control transfers to purchasers at delivery points downstream of the processing plant. The gathering, processing and compression fees are presented as GP&T, and any transportation and fractionation costs incurred subsequent to the point of transfer of control are reflected as a net reduction to natural gas and NGL sales revenues presented in the table above.
Performance obligations
For all commodity products, the Company records revenue in the month production is delivered to the purchaser. Settlement statements for certain natural gas and NGL sales may not be received for 30 to 90 days after the date production volumes are delivered and for crude oil, generally within 30 days after delivery has occurred. However, payment is unconditional once the performance obligations have been satisfied. At this time, the volume and price can be reasonably estimated and amounts due from customers are accrued in accounts receivable, net in the Consolidated Balance Sheets. As of September 30, 2018 and December 31, 2017, such receivable balances were $68.1 million and $52.9 million, respectively.
The Company records any differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Historically, any identified differences between revenue estimates and actual revenue received have not been significant. For the nine months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
Transaction price allocated to remaining performance obligations
For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC Topic 606 which states the Company is not required to disclose the transaction price allocated to the remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, monthly sales of a product generally represent a separate performance obligation; therefore, future commodity volumes to be delivered and sold are wholly unsatisfied and disclosure of the transaction price allocated to such unsatisfied performance obligations is not required.
Note 14—Subsequent Events
Credit Facility Amendment
In connection with the October 2018 semi-annual credit facility redetermination, the borrowing base under the revolving credit facility was increased from $800.0 million to $1.0 billion and the lenders increased their aggregate elected commitments from $600.0 million to $800.0 million.



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Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation
The following discussion and analysis of our financial condition and results of operation should be read in conjunction with the accompanying consolidated financial statements and related notes. 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 above in “Cautionary Statement Regarding Forward-Looking Statements” and in our 2017 Annual Report under the heading “Item 1A. Risk Factors,” 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
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. 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. During 2015 and 2016, global and domestic oil supply continued to outpace demand resulting in ongoing low realized oil and gas prices. In 2017 and thus far into 2018, commodity prices have improved yet remain 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 2016:
 
2016
 
2017
 
2018
 
Q1
 
Q2
 
Q3
 
Q4
 
Q1
 
Q2
 
Q3
 
Q4
 
Q1
 
Q2
 
Q3
Crude oil (per Bbl)
$
33.49

 
$
45.70

 
$
45.00

 
$
49.27

 
$
51.82

 
$
48.32

 
$
48.17

 
$
55.31

 
$
62.91

 
$
68.07

 
$
69.50

Natural gas (per MMBtu)
$
1.98

 
$
2.25

 
$
2.80

 
$
3.17

 
$
3.06

 
$
3.14

 
$
2.95

 
$
2.91

 
$
3.08

 
$
2.85

 
$
2.93

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 pre-2015 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 (including realized differentials) 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 realized 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.
2018 Highlights and Future Considerations
Operational Highlights
We operated, on average, a seven-rig drilling program during the first nine months of 2018 which enabled us to complete and bring online 22 gross operated wells in the third quarter and 58 gross operated wells year to date. The total number of completed wells during the year had an average effective lateral length of approximately 7,500 feet.
Acquisition and Divestiture Highlights
On February 8, 2018, we completed the acquisition of approximately 4,000 undeveloped net acres, as well as certain producing properties, 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 a 92% average working interest and is largely contiguous to Centennial’s existing position.

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Table of Contents

On March 2, 2018, we completed the sale of approximately 8,600 undeveloped net acres and 12 gross producing wells located in Reeves County, Texas for a total unadjusted sales price of $140.7 million. The divested acreage represents a largely non-operated position (32% average working interest) on the western portion of Centennial’s acreage in Reeves County. The properties divested consisted 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 769 Boe/d (608 Bbls/d) in the first quarter of 2018.
Financing Highlights
On May 4, 2018, the Company entered into an amended and restated credit agreement (the “Amended Agreement”) with a syndicate of banks, the majority of which were lenders to the Company’s existing credit agreement. Under the Amended Agreement, the borrowing base increased from $575.0 million to $800.0 million and aggregate elected commitments increased from $475.0 million to $600.0 million. The Amended Agreement also provided for lower rates and fees compared to the existing credit agreement, with varying rates depending on the percentage of the borrowing base utilized, as follows: the LIBOR margin decreased from the range of 225 to 325 basis points to 150 to 250 basis points; the alternate base rate margin decreased from the range of 125 to 225 basis points to 50 to 150 basis points; and the commitment fees, which are paid on unused amounts of the revolving credit facility, were reduced from 50 basis points to a range of 37.5 to 50 basis points. The credit facility under the Amended Agreement has a term of five years.
In connection with the October 2018 credit facility semi-annual redetermination, the borrowing base under the revolving credit facility was increased from $800.0 million to $1.0 billion and the lenders increased their aggregate elected commitments from $600.0 million to $800.0 million.





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Table of Contents

Results of Operations
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017
The following table provides the components of our 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 average prices and average daily production volumes:

For the Three Months Ended September 30,
 
Increase/(Decrease)

2018
 
2017

$

%
Operating revenues (in thousands):







Oil sales
$
184,510


$
87,286


$
97,224


111
 %
Natural gas sales
14,311


12,852


1,459


11
 %
NGL sales
36,059


11,473


24,586


214
 %
Oil and gas sales
$
234,880


$
111,611