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 June 30, 2017March 31, 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
Indicate by check mark 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 oý
 
Accelerated filer o
 
Non-accelerated filer ýo
(Do not check if a smaller reporting company)
 
Smaller reporting company o
 
Emerging growth company ýo
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 August 7, 2017,April 30, 2018, there were 256,670,839263,745,887 shares of Class A Common Stock, par value $0.0001 per share and 19,155,92112,313,691 shares of Class C Common Stock, par value $0.0001 per share, outstanding.
 

TABLE OF CONTENTS
   Page
Glossary of Oil and Natural Gas Terms
3
  
Glossary of Certain Other Terms
5
  
Cautionary Statement Concerning Forward-Looking Statements
6
  
Part I—FINANCIAL INFORMATION
8
    
Item 1.
 
Financial Statements (Unaudited)
8
    
  
Condensed Consolidated Balance Sheets as of June 30, 2017March 31, 2018 and December 31, 20162017
8
    
  
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30,March 31, 2018 and 2017 and 2016
9
    
  
Condensed Consolidated StatementStatements of Shareholders’ EquityCash Flows for the SixThree Months Ended June 30,March 31, 2018 and 2017
10
    
  
Condensed Consolidated Statements of Cash FlowsShareholders’ Equity for the SixThree Months Ended June 30,March 31, 2018 and 2017 and 2016
1112
    
  
Notes to Condensed Consolidated Financial Statements
1213
    
Item 2.
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
25
    
Item 3.
 
Quantitative and Qualitative Disclosures About Market Risk
3735
    
Item 4.
 
Controls and Procedures
3937
    
Part II—OTHER INFORMATION
4038
    
Item 1.
 
Legal Proceedings
4038
    
Item 1A.
 
Risk Factors
4038
    
Item 6.
 
Exhibits
4038
    
Signatures
4139


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.

Bbl/Bbls/d. One BblBarrels 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 degreeone-degree Fahrenheit.

Completion. InstallationThe process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, for production of oil or natural gas, or, in the case of a dryas well as perforation and fracture stimulation to reporting to the appropriate authority that the well has been abandoned.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.

MBbl. One thousand barrels of crude oil, condensate or NGLs.

MBoe. One thousand Boe.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One Mcf per day.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.


NGLsNGL. Natural gas liquids. HydrocarbonsThese are naturally occurring substances found in natural gas, which may be extracted as liquefied petroleum gasincluding ethane, butane, isobutane, propane and natural gasoline.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 all expected quality, transportation and demand adjustments.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. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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 granted to the lessee of a property to develop anddrill, produce and own natural gas orconduct operations on the property and to a share of production, subject to all royalties and other minerals. The working interest owners bear theburdens and to all costs of exploration, development and operating costsoperations and all risks in connection therewith.

Workover. Operations on either a cash, penaltyproducing well to restore or carried basis.increase production.

WTI. West Texas Intermediate.



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.
CRP. Centennial Resource Production, LLC, a Delaware limited liability company.
CRP Common Units. The units representing common membership interests in CRP.
GMT Acquisition. OurThe 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.
Public Warrants. Warrants for the purchase of shares of Class A Common Stock sold as part of the Units in our IPO, all of which have been exercised or redeemed and are no longer outstanding.
Riverstone. Riverstone Investment Group LLC and its affiliates, including ourSilver 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.
Silverback. Silverback Exploration, LLC and Silverback Operating, LLC, collectively.
Silverback Acquisition. OurThe acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback, which closed on December 28, 2016.
Sponsor. Our sponsor, Silver Run Sponsor, LLC, a Delaware limited liability company and an affiliate of Riverstone.
Units. Our units sold in our IPO, each of which consisted of one share of Class A Common Stock and one-third of one Public Warrant.
Voting common stock. Our Class A Common Stock and Class C Common Stock.


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 report,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 Form 10-Q,Quarterly Report, the words ”could,“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, 2016 (our “20162017 (“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;strategy and future drilling plans; 
our reserves; 
our drilling prospects, inventories, projectsreserves and programs; 
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 natural gas liquids (“NGL”)NGL prices; 
the timing and amount of our future production of oil, natural gas and NGLs; 
our hedging strategy and results;
our future drilling plans; 
our competition and government regulations; 
our ability to obtain permits and governmental approvals; 
our pending legal or environmental matters; 
our marketing of oil, natural gas and NGLs; 
our leasehold or business acquisitions; 
our costs of developing our properties; 
general economic conditions; 
credit markets; 
uncertainty regarding our future operating results; and 
our plans, objectives, expectations and intentions contained in this Form 10-QQuarterly Report that are not historical.
All forward-looking statements, speakexpressed or implied, are made only as of the date of this Form 10-Q.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 20162017 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 Form 10-QQuarterly 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.

All forward-looking statements, expressed or implied, included in this Form 10-QQuarterly 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 Form 10-Q.Quarterly Report.



PART I. FINANCIAL INFORMATION
Item 1.    Financial Statements
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)
(in thousands, except share and per share amounts)
June 30, 2017 December 31, 2016March 31, 2018 December 31, 2017
ASSETS      
Current assets      
Cash and cash equivalents$—
 $134,083
$38,224
 $117,315
Accounts receivable, net34,809
 14,734
108,431
 78,786
Derivative instruments1,516
 431
7,148
 433
Prepaid and other current assets2,431
 2,078
12,521
 6,051
Total current assets38,756
 151,326
166,324
 202,585
Oil and natural gas properties, successful efforts method      
Unproved properties2,122,262
 1,905,661
1,881,979
 1,952,680
Proved properties1,006,202
 605,853
1,855,890
 1,602,002
Accumulated depreciation, depletion and amortization(73,687) (14,436)
(238,676) (173,906)
Total oil and natural gas properties, net3,054,777
 2,497,078
3,499,193
 3,380,776
Other property and equipment, net3,647
 2,193
6,251
 5,465
Total property and equipment, net3,058,424
 2,499,271
3,505,444
 3,386,241
Noncurrent assets      
Derivative instruments131
 —
1,188
 662
Other noncurrent assets1,258
 1,045
19,607
 27,081
Total assets$3,098,569
 $2,651,642
$3,692,563
 $3,616,569
LIABILITIES AND SHAREHOLDERS’ EQUITY   
LIABILITIES AND EQUITY   
Current liabilities      
Accounts payable and accrued expenses$119,508
 $86,100
$180,048
 $199,533
Derivative instruments185
 5,361
—
 240
Other current liabilities483
 —
Total current liabilities119,693
 91,461
180,531
 199,773
Noncurrent liabilities      
Revolving credit facility35,000
 —
Long-term debt, net390,921
 390,764
Asset retirement obligations8,855
 7,226
12,356
 12,161
Deferred tax liability9,069
 —
22,367
 9,899
Derivative instruments—
 20
Other long-term liabilities670
 —
Total liabilities172,617
 98,707
606,845
 612,597
Shareholders’ equity      
Preferred stock, $.0001 par value, 1,000,000 shares authorized:   
Commitments and contingencies (Note 12)

 

Preferred stock, $0.0001 par value, 1,000,000 shares authorized:   
Series A: 1 share issued and outstanding—
 —
—
 —
Series B: no shares issued and outstanding at June 30, 2017 and 104,400 shares issued and outstanding at December 31, 2016—
 —
Common stock, $0.0001 par value, 620,000,000 shares authorized:      
Class A: 257,244,767 shares issued and 256,670,839 shares outstanding at June 30, 2017 and 201,091,646 shares issued and 200,835,049 shares outstanding at December 31, 201626
 20
Class C: 19,155,921 shares issued and outstanding2
 2
Class A: 264,858,498 shares issued and 263,738,776 shares outstanding at March 31, 2018 and 261,337,636 shares issued and 260,327,920 shares outstanding at December 31, 201727
 26
Class C (Convertible): 12,313,691 and 15,661,338 shares issued and outstanding at March 31, 2018 and December 31, 2017, respectively1
 2
Additional paid-in capital2,700,473
 2,364,049
2,814,051
 2,767,558
Retained earnings (accumulated deficit)21,656
 (8,929)
Retained earnings132,729
 66,639
Total shareholders’ equity2,722,157
 2,355,142
2,946,808
 2,834,225
Noncontrolling interest203,795
 197,793
138,910
 169,747
Total equity2,925,952
 2,552,935
3,085,718
 3,003,972
Total liabilities and shareholders’ equity$3,098,569
 $2,651,642
Total liabilities and equity$3,692,563
 $3,616,569
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)
Successor  Predecessor Successor  PredecessorFor the Three Months Ended March 31,
For the Three Months Ended June 30, 2017  For the Three Months Ended June 30, 2016 For the Six Months Ended June 30, 2017  For the Six Months Ended June 30, 20162018 2017
Net revenues         
Oil sales$70,735
  $20,361
 $117,416
  $33,587
Natural gas sales12,133
  1,775
 20,374
  3,088
NGL sales8,196
  1,211
 14,371
  1,793
Total net revenues91,064
  23,347
 152,161
  38,468
Operating revenues   
Oil and gas sales215,898
 61,097
Operating expenses            
Lease operating expenses8,273
  2,597
 15,551
  6,639
16,276
 7,278
Severance and ad valorem taxes4,723
  1,247
 7,910
  2,091
14,173
 3,187
Gathering, processing and transportation expenses7,403
  1,459
 12,647
  2,589
13,828
 5,244
Depreciation, depletion and amortization34,300
  21,182
 60,460
  42,485
66,010
 26,160
Abandonment expense and impairment of unproved properties—
  897
 (29)  897
Impairment and abandonment expenses—
 (29)
Exploration expense2,470
  262
 2,470
  517
3,447
 1,181
General and administrative expenses10,641
  2,607
 22,706
  4,888
14,297
 10,884
Total operating expenses67,810
  30,251
 121,715
  60,106
128,031
 53,905
Total operating income (loss)23,254
  (6,904) 30,446
  (21,638)
   
Income from operations87,867
 7,192
   
Other income (expense)            
Gain (loss) on sale of oil and natural gas properties7,191
  —
 7,357
  (4)15
 166
Interest expense(707)  (1,798) (1,117)  (3,439)(5,813) (410)
Net gain (loss) on derivative instruments2,529
  (7,843) 6,288
  (5,925)7,843
 3,759
Other income—
  6
 —
  6
Other income (expense)9,013
  (9,635) 12,528
  (9,362)(3) —
Income (loss) before income taxes32,267
  (16,539) 42,974
  (31,000)
Income tax (expense) benefit(9,069)  406
 (9,069)  406
Net income (loss)23,198
  (16,133) $33,905
  $(30,594)
Other income (expense)2,042
 3,515
   
Income before income taxes89,909
 10,707
Income tax expense19,137
 —
Net income70,772
 10,707
Less: Net income attributable to noncontrolling interest2,436
  —
 3,320
  —
4,682
 884
Net income (loss) attributable to common shareholders$20,762
  $(16,133) $30,585
  $(30,594)
Income per share:         
Net income attributable to Class A Common Stock$66,090
 $9,823
   
Income per share of Class A Common Stock:   
Basic$0.09
    $0.14
   $0.25
 $0.04
Diluted$0.09
    $0.14
   $0.25
 $0.04
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
 For the Three Months Ended March 31,
 2018
2017
Cash flows from operating activities:   
Net income$70,772
 $10,707
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation, depletion and amortization66,010
 26,160
Stock-based compensation expense4,333
 2,610
Exploratory dry hole cost221
 —
Deferred tax expense19,137
 —
(Gain) loss on sale of oil and natural gas properties(15) (166)
Non-cash portion of derivative (gain) loss(7,482) (4,156)
Amortization of debt issuance costs379
 93
Changes in operating assets and liabilities:   
(Increase) decrease in accounts receivable(29,555) (9,143)
Increase in prepaid and other assets(7) (382)
Increase (decrease) in accounts payable and other liabilities8,033
 (6,475)
Net cash provided by operating activities131,826
 19,248
Cash flows from investing activities:   
Acquisitions of oil and natural gas properties(101,753) (38,678)
Drilling and development capital expenditures(250,548) (62,121)
Purchases of other property and equipment(1,763) (1,139)
Proceeds from sales of oil and natural gas properties135,481
 3,518
Net cash used in investing activities(218,583) (98,420)
Cash flows from financing activities:   
Proceeds from revolving credit facility85,000
 —
Repayment of revolving credit facility(85,000) —
Proceeds from stock options exercised164
 —
Restricted stock used for tax withholdings(192) —
Debt issuance costs(906) (37)
Net cash used in financing activities(934) (37)
Net decrease in cash and cash equivalents and restricted cash(87,691) (79,209)
Cash and cash equivalents and restricted cash, beginning of period125,915
 134,083
Cash and cash equivalents, end of period$38,224
 $54,874
The accompanying notes are an integral part of these unaudited consolidated financial statements.

Supplemental cash flow information and noncash activity (in thousands):
 For the Three Months Ended March 31,
 2018
2017
Supplemental cash flow information   
Cash paid for interest$784
 $226
Supplemental non-cash activity   
Accrued capital expenditures included in accounts payable and accrued expenses$111,824
 $63,978
Asset retirement obligations incurred, including revisions to estimates243
 274


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

Common Stock Preferred Stock          Common Stock Preferred Stock          
Class A Class C Series A Series B Additional Paid-In Capital (Accumulated Deficit) Retained Earnings Total Shareholders’ Equity Noncontrolling Interest Total EquityClass 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 Shares Amount Shares Amount Shares Amount Shares Amount 
Balance at December 31, 2016201,092
 $20
 19,156
 $2
 —
 $—
 104
 $—
 $2,364,049
 $(8,929) $2,355,142
 $197,793
 $2,552,935
201,092
 $20
 19,156
 $2
 —
 $—
 104
 $—
 $2,364,049
 $(8,929) $2,355,142
 $197,793
 $2,552,935
Warrants exercised6,236
 1
 —
 —
 —
 —
 —
 —
 (1) —
 —
 —
 —
6,233
 1
 —
 —
 —
 —
 —
 —
 (1) —
 —
 —
 —
Restricted stock issued324
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
268
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Restricted stock forfeited(7) —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Conversion of Series B preferred shares to Class A common shares26,100
 3
 —
 —
 —
 —
 (104) —
 (3) —
 —
 —
 —
Sale of unregistered Class A common shares23,500
 2
 —
 —
 —
 —
 —
 —
 340,748
   340,750
 —
 340,750
Underwriters' discount and offering expense—
 —
 —
 —
 —
 —
 —
 —
 (7,233) —
 (7,233) —
 (7,233)
Equity based compensation—
 —
 —
 —
 —
 —
 —
 —
 5,595
 —
 5,595
 
 5,595
Stock-based compensation—
 —
 —
 —
 —
 —
 —
 —
 2,610
 —
 2,610
 —
 2,610
Change in equity due to issuance of shares by Centennial Resource Production, LLC—
 —
 —
 —
 —
 —
 —
 —
 (2,682) —
 (2,682) 2,682
 —
—
 —
 —
 —
 —
 —
 —
 —
 2,846
 —
 2,846
 (2,846) —
Net income—
 —
 —
 —
 —
 —
 —
 —
 —
 30,585
 30,585
 3,320
 33,905
—
 —
 —
 —
 —
 —
 —
 —
 —
 9,823
 9,823
 884
 10,707
Balance at June 30, 2017257,245
 $26
 19,156
 $2
 —
 $—
 —
 $—
 $2,700,473
 $21,656
 $2,722,157
 $203,795
 $2,925,952
Balance at March 31, 2017207,593
 $21
 19,156
 $2
 —
 $—
 104
 $—
 $2,369,504
 $894
 $2,370,421
 $195,831
 $2,566,252
                         
Balance at December 31, 2017261,338
 $26
 15,661
 $2
 —
 $—
 —
 $—
 $2,767,558
 $66,639
 $2,834,225
 $169,747
 $3,003,972
Restricted stock issued199
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Restricted stock forfeited(26) —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Restricted stock used for tax withholding(10) —
 —
 —
 —
 —
 —
 —
 (192) —
 (192) —
 (192)
Option Exercises10
 —
 —
 —
 —
 —
 —
 —
 164
 —
 164
 —
 164
Stock-based compensation—
 —
 —
 —
 —
 —
 —
 —
 4,333
 —
 4,333
 —
 4,333
Conversion of common shares from Class C to Class A, net of tax3,347
 1
 (3,347) (1) —
 
 —
 —
 42,188
 —
 42,188
 (35,519) 6,669
Net income—
 —
 —
 —
 —
 —
 —
 —
 —
 66,090
 66,090
 4,682
 70,772
Balance at March 31, 2018264,858
 $27
 12,314
 $1
 —
 $—
 —
 —
 $2,814,051
 $132,729
 $2,946,808
 138,910
 3,085,718


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


CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
 Successor  Predecessor
 For the Six Months Ended June 30, 2017  For the Six Months Ended June 30, 2016
Cash flows from operating activities:    
Net income (loss)$33,905
  $(30,594)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Depreciation, depletion and amortization60,460
  42,485
Equity based compensation expense5,595
  —
Abandonment expense and impairment of unproved properties(29)  897
Deferred tax expense (benefit)9,069
  (406)
(Gain) loss on sale of oil and natural gas properties(7,357)  4
Non-cash portion of derivative (gain) loss(6,412)  20,596
Amortization of debt issuance costs214
  244
Changes in operating assets and liabilities:    
(Increase) decrease in accounts receivable(20,567)  1,782
Increase in prepaid and other assets(172)  (632)
Increase in accounts payable and other liabilities18,434
  1,228
Net cash provided by operating activities93,140
  35,604
Cash flows from investing activities:    
Acquisition of oil and natural gas properties(405,244)  (52,378)
Drilling and development capital expenditures(198,299)  (33,044)
Purchases of other property and equipment(2,457)  (33)
Proceeds from sales of oil and natural gas properties10,675
  —
Net cash used in investing activities(595,325)  (85,455)
Cash flows from financing activities:    
Issuance of Class A common shares340,750
  —
Underwriters discount and offering costs(7,233)  —
Proceeds from revolving credit facility50,000
  55,000
Repayment of revolving credit facility(15,000)  (5,000)
Financing obligation—
  (1,233)
Debt issuance costs(415)  —
Net cash provided by financing activities368,102
  48,767
Net decrease in cash and cash equivalents(134,083)  (1,084)
Cash and cash equivalents, beginning of period134,083
  1,768
Cash and cash equivalents, end of period$—
  $684
Supplemental cash flow information    
Cash paid for interest$723
  $3,089
Supplemental non-cash activity    
Accrued capital expenditures included in accounts payable and accrued expenses$80,651
  $4,574
Asset retirement obligations incurred, including changes in estimate$649
  $134
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1—Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Centennial Resource Development, Inc. (the “Company” or “Centennial”) was originally incorporated in Delaware on November 4, 2015 as a special purpose acquisition company under the name Silver Run Acquisition Corporation for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving the Company and one or more businesses.
On February 29, 2016, the Company consummated its initial public offering of Units each consisting of one share of Class A Common Stock and one-third of one Public Warrant. On October 11, 2016, the Company consummated the acquisition of approximately 89% of the outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company (“CRP” and such acquisition, the “Business Combination”). In connection with the closing of the Business Combination, the Company changed its name from "Silver Run Acquisition Corporation" to "Centennial Resource Development, Inc."
CRP was formed in August 2012 byis an affiliate of NGP Energy Capital Management, a family of energy-focused private equity investment funds, in connection with the acquisition of all of the oil and natural gas properties and certain other assets of Celero, which was formed in 2006 to focus on the development and acquisition of oil and natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas. Until the closing of the Business Combination, CRP operated as a privately-held independent oil and natural gas company.
company focused on the development of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. The Company’s Class A Common Stock trades on The NASDAQ Capital Market (“NASDAQ”) underassets are concentrated in the ticker symbol “CDEV.” The Units automatically separated into their component securities prior to or upon closingDelaware Basin, a sub-basin of the Business Combination and, as a result, no longer trade as a separate security. All of the Company’s Public Warrants were either exercised for shares of Class A Common Stock or, following March 31, 2017, redeemed for $0.01 per Public Warrant and, as a result, the Public Warrants no longer trade on NASDAQ.
The consolidated financial statements include the accounts of the Company and CRPPermian Basin, and its wholly-owned subsidiaries.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 subsidiaries.subsidiary, Centennial Resource Production, LLC (“CRP”).
Principles of Consolidation and Basis of Presentation
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) and the rules and regulations of the SEC.SEC for interim financial reporting. Accordingly, certain disclosures required by U.S. GAAP and normally included in an Annual Report on Form 10-K have been omitted. Although management believes that our disclosures in these interimThe consolidated financial statements are adequate, theyand related notes included in this Quarterly Report should be read in conjunction with our 2016the 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 adjustments, consisting of normal, recurring adjustments and accruals considered necessary for a fair presentation ofto present fairly, in all material respects, the Company’s interim financial information,results, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying condensed consolidated financial statements. The Company has evaluated subsequent events through the date of this filing.
As a result of the Business Combination, the Company is the acquirer for accounting purposes, and CRP is the acquiree and accounting Predecessor. The Company’s financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination on October 11, 2016. The Business Combination was accounted for as a business combination using the acquisition method of accounting, and the Successor financial statements reflect a new basis of accounting that is based on the fair value of the net assets acquired. As a result of the application of the acquisition method of accounting as of the Business Combination, the financial statements for the Predecessor period and for the Successor period are presented on a different basis of accounting.

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


Principles of Consolidation
The consolidated financial statements included herein have been prepared in accordance with U.S. GAAP and the rules and regulations of the SEC. 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. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying consolidated financial statements. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
Noncontrolling interests represent third-party ownership in the Company’s consolidated subsidiary and 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 and combined financial statements requires the Company’s management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.
The more significant areas requiring the use of assumptions, judgments and estimates include: (1)(i) oil and natural gas reserves; (2)(ii) cash flow estimates used in impairment tests of long-lived assets; (3)(iii) depreciation, depletion and amortization; (4)(iv) asset retirement obligations; (5)(v) determining fair value and allocating purchase price in connection with business combinations; (6)combinations and asset acquisitions; (vi) accrued revenue and related receivables; (vii) accrued liabilities; (viii) valuation of derivative instruments; and (7) accrued revenue(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 related receivables.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 January 2017,August 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. This update affects all reporting entities and the objective of the guidance is to assist with evaluation of whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The mandatory effective date for this update is for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The amendments should be applied prospectively on or after the effective date and disclosures are not required at transition. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance. The Company early adopted ASU 2017-01 in the second quarter of 2017. Refer to Note 2—Property Acquisitions for details of the GMT Acquisition.
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. AdoptionThe Company adopted ASU 2016-15 in the first quarter of this standard will only affect2018. As a result of adoption, there were no changes to the presentation of the Company’s cash flows and will not have a material impact on its consolidated financial statements.
In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing. This update clarifies two principles of Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers: identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as ASU 2016-08, Revenue from Contracts with Customers: Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net), the revenue recognition standard discussed below. Although the Company is stillflow activities in the process of assessing its contracts with customers and evaluating the effect of adopting these standards, as well as the transition method to be applied, the adoption is not expected to have a significant impact on the Company’s consolidated financial statements other than additional disclosures. 
In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation. This update applies to all entities that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. This update will be effectiveflows for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. The Company elected to early adopt this guidance in October 2016 in conjunction with the issuance of its equity awards.

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


Inthree months ended March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers: Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net). Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning this update is applied only to the most current period presented. The Company is currently evaluating the impact, if any, that the adoption of this update will have on its financial position, results of operations and liquidity.31, 2018.
In February 2016, the FASB issued ASU 2016-02, Leases, which created Accounting Standard Codification (“ASC”) Topic 842, Leases (“ASC Topic 842”), superseding current lease requirements under ASC Topic 840, Leases. This update appliesSubsequently in January 2018, the FASB issued ASU 2018-01, which provides a practical expedient for the evaluation of existing land easement agreements under ASU 2016-02. ASU 2016-02 and its related amendments apply to any entity that enters into a lease, with some specified scope exemptions. Under this update,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. This updateASC 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. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. Although the Company is still in the process of evaluating the effect of adopting ASU 2016-02 and 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. As of December 31, 2016, theThe Company had approximately $17.0 million of contractual obligations related to its non-cancelable leases, and it will evaluate those contracts as well as otheris currently evaluating existing arrangements to determine if they qualify for lease accounting under ASU 2016-02.ASC Topic 842.
In May 2014, the FASB issued ASU No. 2014-09, which created ASC Topic 606, Revenue from Contracts with Customers (“ASC Topic 606”), which supersedes thesuperseding revenue recognition requirements in ASC Topic 605, Revenue Recognition, and most industry-specific guidance. ASU 2014-09The 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 and supersedes current revenue recognition guidance, including industry-specific revenue guidance.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.
In August 2015, the FASB issued ASU 2015-14, which defers the ASC Topic 606 is effective date of ASU 2014-09 for one year to fiscal years, and interim periods within those years, beginning after December 15, 2017. In May 2016, the FASB issued ASU 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. The standards permitstandard 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 plans to adopt these ASUs effectivehas selected the modified retrospective method and has adopted this guidance as of January 1, 2018. Although2018, the effective date. The Company is still inhas completed its review of the processimpact of assessingthe new standard on its significant contracts with customers and evaluatingconcluded that there was not a material impact to the effectpresentation of adopting these standards,revenues or expenses as well as the transition method to be applied,a result of the adoption is not expectedof this standard. Refer to have a significant impact onNote 13—Revenues for additional disclosures required by the Company’s consolidated financial statements other than additional disclosures. new standard.
Note 2—Property Acquisitions and Divestiture
20172018 Acquisition
On JuneFebruary 8, 2017,2018, the Company completed the GMT Acquisition and acquired interests in 36 producing horizontal wells plusacquisition of approximately 4,000 undeveloped acreage on approximately 11,850 net acres, (14,770 gross acres)as well as certain producing properties, in Lea County, New Mexico for an unadjusted purchase price of $350.0$94.7 million. The Company operates approximately 79% of, and hasoperated acreage position contains an approximate 85%92% average working interest in this acreage. The acquired acres areand is largely contiguous to Centennial’s existing position located in the Northernnorthern Delaware Basin with drilling locationsBasin. 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 Avalon Shale, 2nd Bone Spring Sand, 3rd Bone Spring Sand and Wolfcamp A formations.purchase price upon closing of the transactions. The Company presented the cash in escrow as restricted cash within the line item Other Noncurrent Assets on the Consolidated Balance Sheet as of December 31, 2017.

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


The GMT Acquisitionacquisition was recorded as an asset acquisition under ASU 2017-01.2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. Accordingly, the GMT purchase consideration has been allocated to the GMT oil and natural gas properties based on their relative fair values measured as of the acquisition date. After settlement statement adjustments of $0.9$0.2 million, the Company paid a net purchase price of $349.1$94.5 million. On a relative fair value basis, $296.2$80.7 million was allocated to unproved properties and $53.2$13.8 million to proved properties. Transaction costs incurred and capitalized as they relateof March 31, 2018, amounted to the GMT Acquisition$0.2 million and mainly consistconsisted of advisory and legal and accounting fees and are capitalized as incurred, andfees.

2018 Disposition
On March 2, 2018, the Company has incurred $0.4 million in capitalized transaction costs related to this acquisition ascompleted the sale of June 30, 2017.



14
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


2016 Acquisition
In December 2016, the Company acquired interests in 31 producing horizontal wells plusapproximately 8,600 undeveloped acreage on approximately 35,500 net acres (43,500and 12 gross acres)producing wells located in Reeves County, Texas for ana total unadjusted purchasesales price of $855.0 million,$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 consistedconstituted a partial sale of cash consideration paid by the Companyoil and a $32.3 million payable at December 31, 2016 that was settledgas properties in 2017 when title issues relating to the purchased acreage were satisfied.accordance with ASC 932, Extractive Activities - Oil and Gas. The Company operates approximately 90% of,used the net proceeds from the sale to fund the 2018 acquisition discussed above and has an approximate 90% working interest in this acreage. The Wolfcamp A and Wolfcamp B are producing horizons on this acreage, and the Company believes that this acreage may be prospective for the Wolfcamp C and Avalon and Bone Spring shale formations.
The Silverback Acquisition was recorded using the acquisition method of accounting for business combinations. The allocation of the purchase price is based upon management’s estimates and assumptions related to the fair value of assets acquired and liabilities assumedon the acquisition date using currently available information. Transaction costs relating to this purchase were expensed as incurred. The initial accounting for the Silverback Acquisition is preliminary, and adjustments to provisional amounts (such as certain accrued liabilities) or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about facts and circumstances that existed as of the acquisition date. Since the acquisition date, the Company has recorded adjustments to provisional amounts totaling $0.3 million. These adjustments did not have a material impact on the Company’s previously reported consolidated financial statements, and therefore the Company has not retrospectively adjusted those financial statements.
The table below summarizes the allocation of the $867.8 million adjusted purchase price, based on the acquisition date fair value of the assets acquired and the liabilities assumed as of June 30, 2017:
(in thousands)Silverback Acquisition
Purchase price$867,772
Allocation of purchase price: 
Unproved properties753,763
Proved properties116,700
Other property and equipment56
Liabilities(2,747)
Total$867,772
The pro forma effects of the Silverback Acquisition were insignificant to the Company’s 2016 results of operations.general corporate purposes.
Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
(in thousands)June 30, 2017 December 31, 2016
Accrued oil and gas sales$26,742
 $11,596
Joint interest billings7,713
 2,942
Hedge settlements292
 194
Other62
 2
Accounts receivable, net$34,809
 $14,734

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


(in thousands)March 31, 2018 December 31, 2017
Accrued oil and gas sales receivable$76,545
 $52,891
Joint interest billings22,157
 25,256
Receivables for divestitures9,602
 —
Other127
 639
Accounts receivable, net$108,431
 $78,786
Accounts payable and accrued expenses are comprised of the following:
(in thousands)June 30, 2017 December 31, 2016March 31, 2018 December 31, 2017
Accounts payable$44,478
 $11,210
$37,136
 $64,004
Accrued capital expenditures56,228
 24,038
92,113
 90,511
Revenues payable9,922
 3,815
29,523
 23,390
Payable to Silverback—
 32,293
Accrued underwriting fees—
 7,719
Other8,880
 7,025
Accrued interest7,311
 1,936
Accrued employee compensation and benefits2,974
 8,350
Accrued expenses and other10,991
 11,342
Accounts payable and accrued expenses$119,508
 $86,100
$180,048
 $199,533

Note 4—Long-Term Debt
Credit Agreement
CRP, the Company’s consolidated subsidiary, has a revolving credit agreement with a syndicate of banks that as of June 30, 2017March 31, 2018, had a borrowing base of $350.0$575.0 million which has been committedand elected commitments of $475.0 million. This aggregate commitment by lenders and is available to the Company for borrowing. A portion of the revolving credit facility in an aggregate amount not to exceed $15.0 million may be used to issue letters of credit for the account of CRP or other designated subsidiaries of the Company. As of June 30, 2017,March 31, 2018, the Company had $314.1no borrowings outstanding and $474.1 million in available borrowing capacity, which was net of $35.0 million in borrowings and $0.9 million in letters of credit outstanding.
The amount available to be borrowed under CRP'sCRP’s revolving credit facility is subject to a borrowing base that is redetermined semi-annually each April 1 and October 1 by the lenders in their sole discretion. CRP'sCRP’s credit agreement also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the volumesquantities of CRP’s proved oil and natural gas reserves, and estimated cash flows from these reserves and itsthe Company’s commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if actual borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under itsthe credit agreement. The credit facility provides for interest only payments until October In connection with the April 2018 semi-annual redetermination, on May 4, 2018 the Company amended and restated

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its existing credit agreement expires and all outstanding borrowings are due.
The following table shows five succeeding fiscal yearswith a majority of scheduled maturities forthe lenders to the Company’s long-term debt as of June 30, 2017 (in thousands):existing credit agreement. Refer to
 2017 2018 2019 2020 2021
Long-term debt—
 —
 35,000
 —
 —
Note 14—Subsequent Events for additional information on the new credit facility.
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 report.Quarterly Report. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount and are included in interest expense in the accompanying statementsConsolidated Statements of operations.Operations. The credit facility provides for interest only payments until October 15, 2019, when the credit agreement expires and all outstanding borrowings are due.
CRP’s credit agreement contains restrictive covenants that limit its ability to, among other things: incur additional indebtedness; make investments and loans; enter into mergers; make or declare dividends; enter into commodity hedges exceeding a specified percentage of ourthe Company’s expected production; enter into interest rate hedges exceeding a specified percentage of ourits outstanding indebtedness; incur liens; sell assets; and engage in transactions with affiliates.
CRP’s credit agreement also requires it to maintain compliance with the following financial ratios: (1)(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 under Financial Accounting Standards Board FASB Accounting Standard Codification ASC Topic 815, Derivatives and Hedging and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under ourthe credit agreement and non-cash liabilities under ASC 815)derivative liabilities), of not less than 1.0 to 1.0; and (2)(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 June 30, 2017March 31, 2018 and through the filing of this report.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 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 March 31, 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

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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 $9.1 million as of March 31, 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 (“AROs”ARO”) for the sixthree months ended June 30, 2017:March 31, 2018 (in thousands):
(in thousands)Six Months Ended June 30, 2017
Asset retirement obligations, beginning of period$7,226
Additional liabilities incurred1,443
Liabilities settled(29)
Accretion expense233
Revision to estimated cash flows(18)
Asset retirement obligations, end of period$8,855
Asset retirement obligations at January 1, 2018$12,161
Liabilities acquired16
Liabilities incurred253
Liabilities divested(253)
Accretion expense189
Revisions to estimated cash flows(10)
Asset retirement obligations at March 31, 2018$12,356
Asset retirement obligationsARO 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 the AROsARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates and timing of settlement. To the extent future revisions to these assumptions impact the value of the existing ARO liability, a corresponding offsetting adjustment is made to the oil and natural gas property balance.
Note 6—Equity BasedStock-Based Compensation
The Company has recognized stock-based compensation cost as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.
(in thousands)For the Three Months Ended June 30, 2017 For the Six Months Ended June 30, 2017
Restricted stock awards$1,018
 $1,874
Stock option awards1,967
 3,721
Total equity based compensation expense$2,985
 $5,595
EquityLong 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 June 30, 2017,March 31, 2018, the Company had 11,866,07210,691,760 shares of Class A Common Stock available for future grants. The LTIP provides for grants of stock options including(including incentive stock options (“ISOs”) and nonqualified stock options (“NSOs”)options), stock appreciation rights, (“SARs”), restricted stock, dividend equivalents, restricted stock units (“RSUs”) and other stock or cash basedcash-based awards.
Restricted Stock
Stock-based compensation expense is recognized within both General and administrative expenses and Exploration expense in the Consolidated Statements of Operations. The followingexpense amounts in the table provides information about restricted stockbelow 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 duringunder the six months ended June 30, 2017:LTIP as they occur in determining compensation expense.
 Awards Weighted Average Grant-Date Fair Value
Service-based stock awards:   
Outstanding as of December 31, 2016256,597
 $20.03
Vested—
 $—
Granted324,010
 $18.77
Canceled(6,679) $18.81
Outstanding as of June 30, 2017573,928
 $19.33
Compensation cost for the service-based vesting restricted shares is based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period. Unrecognized compensation cost related to unvested
 For the Three Months Ended March 31,
(in thousands)2018 2017
Restricted stock awards$1,775
 $856
Stock option awards2,206
 1,754
Performance stock units352
 —
Total stock-based compensation expense$4,333
 $2,610

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Restricted Stock
The following table provides information about restricted stock awards outstanding during the three months ended March 31, 2018:
 Awards Weighted Average Grant Date Fair Value
Unvested balance as of December 31, 20171,009,716
 $17.64
Granted199,320
 $19.00
Vested(63,367) $18.50
Forfeited(25,948) $16.85
Unvested balance as of March 31, 20181,119,721
 $17.85
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 $19.00 per share and $18.82 per share for the three months ended March 31, 2018 and 2017, respectively. The total fair value of restricted stock awards that vested during the three-month period ended March 31, 2018 was $1.2 million. Unrecognized compensation cost related to restricted shares at June 30, 2017that were unvested as of March 31, 2018 was $8.8 million. The$16.6 million, which the Company expects to recognize that cost over a weighted average period of 2.42.2 years.
Stock Options
OptionsStock options that have been granted under the LTIP expire ten years from the grant date and have service-based vesting schedules of three years.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 byon 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 re-levered asset volatility implied by a set of comparable companies. Expected term is based on the simplified method and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.
The following table summarizes the assumptions and related information used to determine the grant dategrant-date fair value of stock options awarded during the sixthree months ended June 30, 2017:March 31, 2018:
Six Months Ended June 30, 2017For the Three Months Ended March 31,
Weighted average grant-date fair value$7.15
2018 2017
Weighted average grant-date fair value per share$7.96
 7.21
Expected term (in years)6
6
 6
Expected stock volatility38.1%37% 38.2%
Dividend yield—%—% —%
Risk-free interest rate2.0%2.3% 2.0%
Information
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The following table provides information about stock option awards outstanding stock options is summarized induring the table below:three months ended March 31, 2018:
Options Weighted Average Exercise Price 
Weighted Average Remaining Term
(in years)
 
Aggregate Intrinsic Value
(in thousands)
Options Weighted Average Exercise Price 
Weighted Average Remaining Term
(in years)
 
Aggregate Intrinsic Value
(in thousands)
Outstanding as of December 31, 20162,735,500
 $14.67
 5.8
 $13,804
Outstanding as of December 31, 20174,290,001
 $16.15
  
Granted37,000
 $20.00
  
Exercised—
 $—
 —
 $—
(10,000) $16.43
  
Granted1,547,500
 $17.97
 5.6
 $36
Forfeited(223,000) $14.54
 5.3
 $289
(47,668) $14.95
  
Outstanding as of June 30, 20174,060,000
 $15.94
 5.5
 $3,018
Exercisable as of June 30, 2017—
 $—
 —
 $—
Outstanding as of March 31, 20184,269,333
 $16.20
 8.78 $9,417
Exercisable as of March 31, 20181,211,612
 $15.83
 8.69 $2,911
Unvested Options at March 31, 20183,057,721
 $16.28
 8.81 $6,506
As of June 30, 2017,March 31, 2018, there was $21.2$16.6 million of unrecognized compensation cost related to non-vestedunvested stock options. Theoptions, which the Company expects to recognize that cost on a pro ratapro-rata basis over a weighted average period of 2.51.77 years.
Performance Stock Units
During the three months ended March 31, 2018, there was no significant performance stock units activity. As of March 31, 2018, there was $3.2 million of unrecognized compensation cost related to performance stock units that were unvested, which the Company expects to recognize on a pro-rata basis over a weighted average period of 2.3 years.
Note 7—Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations and it usesmay use derivative instruments mainly to manage its exposure to commodity price risk.risk from time to time.
Commodity Derivative Contracts
Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. The Company periodically uses derivative instruments, such as swaps, costless collars and basis swaps, to mitigate its exposure to declines in commodity prices and to the corresponding negative impacts such declines can have on its cash flow available for reinvestment.from operations, returns on capital and other financial results. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. The Company does not enter into derivative contracts for speculative or trading purposes.
Commodity Swap Contracts. The Company opportunistically uses commodity derivative instruments. Currently, the Company utilizes basis swaps to hedge the difference between the index price and a local index price. All transactions are settled in cash with one party paying the other for the resulting difference multiplied by the contract volume.
The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of June 30, 2017:March 31, 2018:
 Period Volume (Bbl) 
Weighted Average Differential ($/Bbl) (1)
Crude oil basis swapsApril 2018 - June 2018 455,000
 $0.18
 April 2018 - December 2018 1,375,000
 $0.00
(1)
The oil basis swap contracts are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING settlements during the relevant calculation period.

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 Period Volume (Bbl) Weighted Average Fixed Price ($/Bbl)
Crude oil swapsJuly 2017 - December 2017 340,400
 $50.41
 January 2018 - December 2018 36,500
 $55.95
Crude oil basis swapsJuly 2017 - November 2017 51,742
 $(0.20)
      
 Period Volume (MMBtu) Weighted Average Fixed Price ($/MMBtu)
Natural gas swapsJuly 2017 - December 2017 736,000
 $2.94
 Period Volume (MMBtu) 
Weighted Average Differential ($/MMBtu) (1)
Natural gas basis swapsApril 2018 - December 2018 1,375,000
 $(0.43)
 January 2019 - December 2019 1,825,000
 $(0.43)
Commodity Swap Contracts. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. In addition, the Company has entered into basis swap contracts in order to hedge the difference between the NYMEX index price and a local index price. When the actual differential exceeds the fixed price provided by the basis swap contract, the Company receives the difference from the counterparty; when the differential is less than the fixed price provided by the basis swap contract, the Company pays the difference to the counterparty.
(1)
The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and the NYMEX price of Natural Gas during the relevant calculation period.
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 condensed consolidated statementsConsolidated Statements of operations.Operations. All derivative instruments are recorded at fair value in the condensed consolidated balance sheets,Consolidated Balance Sheets, other than derivative instruments that meet the “normal purchase normal sale” exclusion, and any gains and losses are recognized in current period earnings.
The following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for the periods presented:
Successor  Predecessor Successor  PredecessorFor the Three Months Ended March 31,
(in thousands)For the Three Months Ended June 30, 2017  For the Three Months Ended June 30, 2016 For the Six Months Ended June 30, 2017  For the Six Months Ended June 30, 20162018 2017
Realized gain (loss) on derivative instruments$361
 $(397)
Unrealized gain (loss) on derivative instruments7,482
 4,156
Net gain (loss) on derivative instruments$2,529
  $(7,843) $6,288
  $(5,925)$7,843
 $3,759
Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives are measured at fair value and are included in the accompanying condensed consolidated balance sheetsConsolidated Balance Sheets as derivative assets and liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master netting agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The following tables summarizetable below summarizes the location and fair value amounts and the classification in the Consolidated Balance Sheets of all the Company’s derivative instruments incontracts outstanding at the consolidatedrespective balance sheets, as well assheet dates. Refer to Note 8—Fair Value Measurements for details of the gross recognizedand net derivative assets, liabilities and offset amounts offsetas presented in the condensed consolidated balance sheets:Consolidated Balance Sheets.
June 30, 2017  Gross Asset/Liability Amounts
(in thousands)Balance Sheet Classification Gross Asset/Liability Amounts Gross Amounts Offset (1) Net Recognized Fair Value Assets/LiabilitiesBalance Sheet Classification March 31, 2018 December 31, 2017
Derivative Assets          
Derivative instrumentsCurrent assets $1,675
 $(159) $1,516
Current assets $7,148
 $720
Derivative instrumentsNoncurrent assets 131
 —
 131
Noncurrent assets 1,188
 662
Total derivative assets $1,806
 $(159) $1,647
 $8,336
 $1,382
Derivative Liabilities          
Derivative instrumentsCurrent liabilities $344
 $(159) $185
Current liabilities $—
 $527
Total derivative liabilities $344
 $(159) $185
(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.

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 December 31, 2016
(in thousands)Balance Sheet Classification Gross Asset/Liability Amounts Gross Amounts Offset (1) Net Recognized Fair Value Assets/Liabilities
Derivative Assets       
Derivative instrumentsCurrent assets $739
 $(308) $431
Total derivative assets  $739
 $(308) $431
Derivative Liabilities       
Derivative instrumentsCurrent liabilities $5,669
 $(308) $5,361
Derivative instrumentsNoncurrent Liabilities 20
 —
 20
Total derivative liabilities  $5,689
 $(308) $5,381
(1)The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements or contract termination.
Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are lenders under CRP’s credit agreement. The Company uses only credit agreement participants to hedge with, since these institutions are secured equally with the holders of any CRP bank debt, which eliminates the potential need to post collateral when Centennialthe 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 member oflender under CRP’s credit facility as referenced above.

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Note 8—Fair Value Measurements
Assets and Liabilities Measured atRecurring Fair Value on a Recurring BasisMeasurements
The Company has categorized itsfollows 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 basedinto one of three different levels depending on the priorityobservability 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 technique, into a three-level fair value hierarchy. Level 1 inputsmethodology are the highest priority and consist of unadjusted 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, for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. indirectly, for substantially the full term of the financial instrument.
Level 33:  Significant Unobservable Inputs – inputs to the valuation methodology are unobservable inputs for an asset or liability.and significant to the fair value measurement.
The following table is a listing of 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 June 30, 2017March 31, 2018 and December 31, 2016:2017:
(in thousands)Level 1 Level 2 Level 3
Commodity derivative asset (liability)     
June 30, 2017$—
 $1,462
 $—
December 31, 2016—
 (4,950) —
(in thousands)Level 1 Level 2 Level 3 
Netting Adjustments(1)
 Net Amounts Presented on the Balance Sheets
March 31, 2018         
Financial assets         
Commodity derivative asset - current$—
 $7,148
 $—
 $—
 $7,148
Commodity derivative asset - noncurrent—
 1,188
 —
 —
 1,188
Total financial assets$—
 $8,336
 $—
 $—
 $8,336
          
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 Level 1, Level 2 or Level 3any of the fair value levels during any period presented.
Derivatives
The Company uses Level 2 inputs to measure the fair value of oil and natural gas commodity derivatives. The Company uses industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
Nonrecurring Fair Value Measurements

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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 during 20162018 and 2017.
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 valuevalues 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 theits variable interest rates are reflective oftied to current market conditions.rates and the applicable credit spreads represent current market rates for the credit risk profile of the Company. As of March 31, 2018 and December 31, 2017, the fair value of the Senior Notes was $392.5 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
On May 25, 2017,Stock. No cash proceeds were received by the Company’s stockholders approved at a special meeting the issuanceCompany in connection with this offering and 3,347,647 shares of 26,100,000CRP Common Units (and corresponding shares of Class C Common Stock) were converted to shares of Class A Common Stock uponon a one-to-one basis. A tax benefit of $6.7 million was recorded in equity as a result of the conversion of 104,400 shares of Series B Preferred Stock issued and sold to affiliates of Riverstone Investment Group LLC in a private placement. The proceeds offrom the Series B Preferred Stock issuance were used to fund a portion of the cash consideration for the December 2016 Silverback Acquisition.
On May 4, 2017, the Company entered into subscription agreements with certain investors, pursuant to which such investors agreed to purchase, in the aggregate, 23,500,000 shares of Class A Common Stock at a purchase price of $14.50 per share, for gross proceeds of approximately $340.8 million. The closing under the subscription agreements occurred concurrently with the closing of the GMT Acquisition on June 8, 2017 and the proceeds were used to fund a majority of the purchase price of that acquisition.
Warrants
On March 1, 2017, the Company delivered a notice of redemption to holders of the Public Warrants originally sold as part of the Units in the IPO announcing its intention to redeem any Public Warrants that remained unexercised and outstanding after March 31, 2017 for $0.01 per Public Warrant. As permitted under the warrant agreement, the notice of redemption required all holders exercising their Public Warrants prior to March 31, 2017 to do so on a “cashless basis” and surrender their Public Warrants for a number of shares of Class A Common Stock equal to the product of (a) the quotient of (i) the difference between $11.50 and $18.44 (the average last sale price of the Class A Common Stock for the ten trading days ending on February 24, 2017) divided by (ii) $18.44, or approximately 0.376, multiplied by (b) the number of Public Warrants held by such holder, rounded down to the nearest whole share. As of June 30, 2017, all of the Company’s Public Warrants have been either exercised for shares of Class A Common Stock or redeemed for $0.01 per Public Warrant. As a result of all such Warrants exercised, the Company issued in aggregate 6,235,790 shares of Class A common stock to holders of Public Warrants.
As of June 30, 2017, 8,000,000 Private Placement warrants were outstanding. Private Placement Warrants are non-redeemable so long as they are held by the Company’s Sponsor or its permitted transferees.noncontrolling interest owner.
Noncontrolling Interest
The noncontrolling interest inrelates to CRP is represented by 19.2 million shares of Class C Common StockUnits that were originally issued to the Centennial Contributors in connection with the Business Combination and iscontinue to be held by holders other than the Company. AsAt the date of June 30, 2017, the Company’sBusiness Combination, the noncontrolling interest was 6.9%, which declined from 7.6%represented 10.9% of the ownership in CRP. The noncontrolling interest percentage is affected by various equity transactions such as, of March 31, 2017, due to the issuance of 23.5 million shares ofCRP Common Unit and Class C Common Stock exchanges and Class A Common Stock on June 8,activities.
As of March 31, 2018, the noncontrolling interest ownership of CRP decreased to 4.5% from 5.7% as of December 31, 2017. The decrease was the result of the exchange of CRP Common Units (and corresponding shares of Class C Common Stock) for Class A Common Stock in March 2018 as discussed in the preceding section above.
The Company has consolidatedconsolidates the financial position, and results of operations and cash flows of CRP and reflectedreflects that portion retained by the other holders of CRP Common Units as a noncontrolling interest.
The following table summarizes Refer to the activityConsolidated Statements of Shareholders’ Equity for a summary of the equityactivity attributable to the noncontrolling interest income:

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


 Successor  Predecessor Successor  Predecessor
(in thousands)For the Three Months Ended June 30, 2017  For the Three Months Ended June 30, 2016 For the Six Months Ended June 30, 2017  For the Six Months Ended June 30, 2016
Net income attributable to noncontrolling interest$2,436
  $—
 $3,320
  $—
during the period.
Note 10—Income Taxes
CRP is treated as a partnership for U.S. federal and most applicable state and local income tax purposes, and Centennial consolidates the financial results of CRP. As a partnership, CRP is not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by CRP is passed through to and included in the taxable income or loss of its members, including the Company, on a pro rata basis. The Company is subject to U.S. federal income taxes, in addition to state and local income taxes with respect to its allocable share of any taxable income or loss of CRP, as well as any stand-alone income or loss generated by the Company.
Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provision for income taxes for the three and six months ended June 30, 2017 and 2016 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to pre-tax income primarily because of state income taxes and estimated permanent differences.
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.
The Company’s policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. However, no uncertain tax positions were identified as of any date on or before June 30, 2017. 
Note 11—Earnings Per Share
Basic earnings per share (“EPS”) is calculated by dividing net income available to common shareholdersClass A Common Stock by the weighted average shares of Class A Common Stock outstanding during each period. Dilutive netDiluted EPS is calculated by dividing adjusted net income available to common shareholdersClass A Common Stock by the weighted average numbershares of diluted common sharesClass 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 awards,and performance stock units, outstanding stock options and warrants using the treasury stock method, and (ii) the Company’s Class C common stockCommon Stock using the “if-converted” method.method, which is net of tax.


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


The Company’s sharestwo-class method of Series B Preferred Stock were converted into shares of Class A Common Stock on May 25, 2017 as a result of shareholder vote. As such, the Company no longer has anycomputing earnings per share is required for entities that have participating sharessecurities. The two-class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and therefore does not utilize the two-class method. 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 the 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 and as such were considered participating securities for the three months ended March 31, 2017. 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 March 31, 2018.
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:

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


(in thousands, except per share data)For the Three Months Ended June 30, 2017 For the Six Months Ended June 30, 2017
Net income attributable to common shareholders$20,762
 $30,585
Add: Income from conversion of Class C Common Stock1,477
 1,995
Adjusted net income attributable to common shareholders22,239
 32,580
    
Basic net earnings per share$0.09
 $0.14
Diluted net earnings per share$0.09
 $0.14
    
Basic weighted average shares outstanding223,623
 212,759
Add: Dilutive effects of equity awards925
 2,046
Add: Dilutive effects of conversion19,156
 19,156
Diluted weighted average shares outstanding243,704
 233,961
 For the Three Months Ended March 31,
(in thousands, except per share data)2018 2017
Net income attributable to Class A Common Stock$66,090
 $9,823
Less: Income allocable to participating securities—
 1,125
Adjusted net income attributable to Class A Common Stock66,090
 8,698
    
Basic net earnings per share of Class A Common Stock$0.25
 $0.04
Diluted net earnings per share of Class A Common Stock$0.25
 $0.04
    
Basic weighted average shares of Class A Common Stock outstanding261,324
 201,776
Add: Dilutive effects of equity awards3,859
 3,166
Diluted weighted average shares of Class A Common Stock outstanding265,183
 204,942
For the three months ended March 31, 2018, the diluted earnings per share calculation excludes 0.2 million stock options that were out-of-the-money and 14.7 million weighted average shares of Class C Common Stock as their impacts were anti-dilutive. For the three months ended March 31, 2017, the diluted earnings per share calculation excludes 4.1 million stock options that were out-of-the-money and 19.1 million weighted average shares of Class C Common Stock as their impacts were anti-dilutive.

Note 12—11—Transactions with Related Parties
Customer and Supplier Relationships
Riverstone Affiliated Companies. Companies
Riverstone and its affiliates, beneficially own more than 10% equity interest in the Company and are therefore considered related parties. From time to time, the Company obtains services related to its drilling and completion activities from affiliates of Riverstone. In particular, the Company has paid the following amounts to the followingcertain affiliates of Riverstone for such services: (i) approximately $27.7 million and $40.2$12.5 million during the three and six months ended June 30,March 31, 2017 (Successor), respectively, to Liberty Oilfield Services, LLC (“Liberty”);LLC; and (ii) approximately $1.3$2.0 million and $2.4$1.1 million during the three and six months ended June 30,March 31, 2018 and 2017, (Successor), respectively, to Permian Tank and Manufacturing, Inc. Inc. (“Permian”). At June 30, 2017, included in IncludedinAccounts payable and accrued expenses on the Consolidated Balance Sheets was $10.1$0.9 million and $0.4$0.3 million due to LibertyPermian as of March 31, 2018 and Permian,December 31, 2017, respectively.
Other Affiliated Companies. Companies
Mark G. Papa, ourthe Company’s President, Chief Executive Officer and Chairman of the Board, serves as a director and Chairman of the Board of Oil States International, Inc., an energy services company publicly traded on the New York Stock Exchange (“Oil States”). From time to time, the Company obtains services related to drilling and completion activities from Oil States. During the three and six months ended June 30, 2017 (Successor),In particular, the Company paid approximately $3.2$2.3 million and $3.9$0.7 million for the three months ended March 31, 2018 and 2017, respectively, to Oil States. At June 30, 2017, includedIncluded in Accounts payable and accrued expenses on the Consolidated Balance Sheets was $0.9$1.6 million and $1.5 million due to Oil States.
NGP Affiliated Companies. BeginningStates as of March 31, 2018 and December 28, 2016, NGP and entities affiliated with NGP were no longer considered related parties of the Company and any expenses incurred on or after December 28, 2016 with NGP and entities affiliated with NGP are no longer classified as related party expenses. However, expenses incurred before December 28, 2016 with NGP and entities affiliated with NGP were classified as related party expenses and are detailed below.
In May 2016, the Company acquired acreage in close proximity to its operating area in Reeves County, Texas and wellbore only rights in an uncompleted horizontal wellbore for approximately $9.8 million from Caird DB, LLC, an affiliate of NGP. In addition, the Company has paid approximately $2.1 million and $3.3 million during the three and six months ended June 30, 2016 (Predecessor), respectively, to RockPile Energy Services, LLC (“Rockpile”). On July 3,31, 2017, Rockpile was acquired by an unrelated third party and is no longer an affiliate of NGP.
The Company is party to a 15-year natural gas gathering agreement with PennTex Permian, LLC (“PennTex”), an NGP-affiliated company, which terminates on April 1, 2029 and is subject to one-year extensions at either party’s election. Under the agreement, PennTex gathers and processes the Company’s natural gas. PennTex purchases the extracted natural gas liquids from the Company, net of gathering fees and an agreed percentage of the actual proceeds from the sale of the residue natural gas and natural gas liquids. Net payments received from PennTex for the three and six months ended June 30, 2016 (Predecessor) were$0.4 million and $0.5 million, respectively. In the third quarter of 2016, PennTex sold its assets related to this agreement to an unrelated third party.





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


Note 13—12—Commitments and Contingencies
Commitments
In June 2017,March 2018, the Company entered into a natural gas transportation service agreement by which the Companywhereby it is required to deliver 40,000approximately 18,500,000 MMBtu per dayover a two-year term or else pay for a term of one year.any volume deficiencies. This delivery commitment is tied to the Company’s natural gas production in Reeves County, Texas, and Ward Counties, Texas.the aggregate financial commitment of $11.0 million under this contract represents the minimum commitments pursuant to the terms of the agreement as of March 31, 2018. Actual expenditures under this contract may exceed this minimum commitment amount.
The Company routinely enters or extends operating agreements, office and equipment leases, drilling and completion rig contracts, among others, in the ordinary course of business. Other than the above, there have been no material, non-routine changes in commitments during the sixthree months ended June 30, 2017.March 31, 2018. Please refer to Note 13—Commitment13—Commitments and Contingencies included in Part II, Item 8.8 in our 2016the Company’s 2017 Annual Report.
Contingencies
In the ordinary course of business, theThe 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 legal actions. Managementclaims cannot be predicted with certainty, management believes it is remote that the impact of such matters that are reasonably possible to occur will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Management is unaware of any pending litigation brought against the Company requiring the reserve of a contingent liability as of the date of these condensed consolidated financial statements.
Note 13—Revenues
Revenue from Contracts with Customers
Sales of oil and 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 contracts’ 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 the 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 March 31,
 2018 2017
Operating revenues (in thousands):   
Oil sales$174,841
 $46,681
Natural gas sales18,580
 8,241
NGL sales22,477
 6,175
Oil and gas sales$215,898
 $61,097
Oil sales
The Company’s 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.

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


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 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 is 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 Sheet. As of March 31, 2018 and December 31, 2017, such receivable balances were $76.5 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 three months ended March 31, 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 Agreement
On May 4, 2018, the Company entered into an amended and restated credit agreement (the “Amended Agreement”) with a majority of the 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 elected commitments increased from $475.0 million to $600.0 million. The credit facility under the Amended Agreement has a term of five years.
The Amended Agreement’s interest rate and utilization fee structure is similar to the existing credit agreement described in Note 4—Long-Term Debt. However, the Amended Agreement provides for lower rates and fees, which vary 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 or 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.


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 condensed 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, and 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 20162017 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
We areCentennial 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 production growth. We also selectively pursue acquisitions that complement our existing core properties, such as the Silverback Acquisition and GMT Acquisition.return on capital.
Market Conditions
The oil and natural gas industry is cyclical and commodity prices can be volatile. In the second half of 2014, oil prices began a rapid and significant decline as global and domestic supply began to outpace demand. During 2015 and through 2016, global and domestic oil supply continued to outpace demand resulting in further deterioration inongoing low realized oil and gas prices. ThusIn 2017 and thus far into 2017, oil2018, commodity prices have beenimproved yet remain volatile, and it is likely that oilcommodity prices will continue to fluctuate due to the ongoing global supply and demand, imbalance, high inventoriesinventory supply levels, weather conditions, geopolitical and geopoliticalother factors.
The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2015:2016:
2015 2016 20172016 2017 2018
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1
Crude oil (per Bbl)$48.62
 $57.84
 $46.60
 $42.16
 $33.59
 $45.70
 $45.00
 $49.27
 $51.82
 $48.32
$33.49
 $45.70
 $45.00
 $49.27
 $51.82
 $48.32
 $48.17
 $55.31
 $62.91
Natural gas (per MMBtu)$2.81
 $2.74
 $2.73
 $2.24
 $1.98
 $2.25
 $2.80
 $3.17
 $3.06
 $3.14
$1.98
 $2.25
 $2.80
 $3.17
 $3.06
 $3.14
 $2.95
 $2.91
 $3.08
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 2014pre-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 may reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore potentially lower our oil, natural gas and NGL reserve quantities.
Lower commodity prices in the future could result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity or ability to finance planned capital expenditures. Lower oil, natural gas and NGLcommodity 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. Alternatively, higher oil and natural gas prices may result in significant non-cash fair value losses being incurred on our derivatives, which could cause us to experience net losses when oil and natural gas prices rise. 
20172018 Highlights and Future Considerations
Operational Highlights
WeFor the three months ended March 31, 2018, we operated, on average, a five rigseven-rig drilling program for a majorityand completed 16 gross operated productive wells. This total number of the second quarter and added a sixth operated rig in Reeves County during late May. During the second quarter, 20 operated wells were spud and 20 operated wells were completed with several wells being placed on production during late June. The completed wells during the quarter had an average effective lateral length of approximately 4,8407,700 feet.
Acquisition and Divestiture Highlights

In June 2017,On February 8, 2018, we completed the acquisition of interests in 36approximately 4,000 undeveloped net acres, as well as certain producing horizontal wells plus undeveloped acreage on approximately 11,850 net acresproperties, in the core of the Northern Delaware Basin in Lea County, New Mexico from GMT Exploration Company LLC for an unadjusted purchase price of $350.0$94.7 million. The operated acreage position contains 92% average working interest and is largely contiguous to Centennial’s existing position.

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 235 Boe/d (less than 1%) of our 2017 average daily net production.
Financing Highlights
In connectionOn May 4, 2018, the Company entered into an amended and restated credit agreement (the “Amended Agreement”) with the GMT Acquisition, in June 2017, we issued and sold in a private placement 23,500,000 shares of our Class A Common Stock to certain other investors, resulting in gross proceeds of approximately $341.0 million, which were used to fund the majority of the acquisition purchase price.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 elected commitments increased from $475.0 million to $600.0 million. The credit facility under the Amended Agreement has a term of five years.


Results of Operations
Three Months Ended June 30, 2017 (Successor)March 31, 2018 Compared to Three Months Ended June 30, 2016 (Predecessor)March 31, 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:
Successor  Predecessor Increase/(Decrease)For the Three Months Ended Increase/(Decrease)
For the Three Months Ended June 30, 2017  For the Three Months Ended June 30, 2016 $ %March 31, 2018 March 31, 2017 $ %
Net revenues (in thousands):        
Operating revenues (in thousands):       
Oil sales$70,735
  $20,361
 $50,374
 247 %$174,841
 $46,681
 $128,160
 275 %
Natural gas sales12,133
  1,775
 10,358
 584 %18,580
 8,241
 10,339
 125 %
NGL sales8,196
  1,211
 6,985
 577 %22,477
 6,175
 16,302
 264 %
Total net revenues$91,064
  $23,347
 $67,717
 290 %
Oil and gas sales$215,898
 $61,097
 $154,801
 253 %
               
Average sales prices:               
Oil (per Bbl)$44.57
  $41.64
 $2.93
 7 %$61.53
 $49.45
 $12.08
 24 %
Effect of derivative settlements on average price (per Bbl)0.24
  12.36
 (12.12) (98)%(0.09) 0.28
 (0.37) (132)%
Oil net of hedging (per Bbl)$44.81
  $54.00
 $(9.19) (17)%$61.44
 $49.73
 $11.71
 24 %
               
Average NYMEX price for oil (per Bbl)$48.32
  $45.70
 $2.62
 6 %$62.91
 $51.82
 $11.09
 21 %
               
Natural gas (per Mcf)$2.78
  $2.04
 $0.74
 36 %$2.42
 $2.91
 $(0.49) (17)%
Effect of derivative settlements on average price (per Mcf)(0.02)  —
 (0.02) 100 %(0.01) 0.05
 (0.06) (120)%
Natural gas net of hedging (per Mcf)$2.76
  $2.04
 $0.72
 35 %$2.41
 $2.96
 $(0.55) (19)%
               
Average NYMEX price for natural gas (per Mcf)$3.14
  $2.25
 $0.89
 40 %$3.08
 $3.06
 $0.02
 1 %
               
NGL (per Bbl)$21.34
  $15.33
 $6.01
 39 %$30.21
 $25.10
 $5.11
 20 %
               
Net production:               
Oil (MBbls)1,587
  489
 1,098
 225 %2,842
 944
 1,898
 201 %
Natural gas (MMcf)4,372
  869
 3,503
 403 %7,683
 2,833
 4,850
 171 %
NGLs (MBbls)384
  79
 305
 386 %
NGL (MBbls)744
 246
 498
 202 %
Total (MBoe) (1)2,700
  713
 1,987
 279 %4,866
 1,662
 3,204
 193 %
               
Average daily net production volume:               
Oil (Bbls/d)17,435
  5,374
 12,061
 224 %31,573
 10,489
 21,084
 201 %
Natural gas (Mcf/d)48,042
  9,549
 38,493
 403 %85,372
 31,478
 53,894
 171 %
NGLs (Bbls/d)4,222
  868
 3,354
 386 %
NGL (Bbls/d)8,267
 2,733
 5,534
 202 %
Total (Boe/d) (1)29,664
  7,833
 21,831
 279 %54,069
 18,469
 35,600
 193 %

(1)Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
Oil, Natural Gas and NGL Sales Revenues. Our totalTotal net revenues for the three months ended June 30, 2017 (Successor)March 31, 2018 were $67.7$154.8 million (or 290%253%) higher than total net revenues for the three months ended June 30, 2016 (Predecessor). Our revenuesMarch 31, 2017. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Our netNet production volumes for oil, natural gas, and NGLs increased 225%201%, 403%171% and 386%202%, respectively, between periods. The oil volume increase between periods resulted primarily from our drilling success in the Delaware Basin, as well as the addition of producing properties we acquired in the Silverback Acquisition. The SilverbackGMT Acquisition, which closed on December 28, 2016, added 17090 MBbls of net oil production to our secondfirst quarter 2018 results. Since the first quarter 2017, results. In addition, we placed 3875 gross operated wells were placed on production in the Delaware Basin, since the second quarter of 2016, which added 1,0761,772 MBbls of net oil productionproduction. The increase in the Company’s operated well count is attributable to the secondcontinued ramp up of development drilling activities and a seven-rig drilling program in the first quarter of 2017.2018. These oil volume increases were partially offset by normal field production declines across several of our existing wells. Our naturalNatural gas and NGLs are produced concurrently with our crude oil volumes,

resulting in a high correlation between fluctuations in our oil quantities sold and our natural gas and NGL quantities sold. Thus,During the reasons that our natural gas and NGL sales volumes have increased significantly between periods similarly relate to the Silverback Acquisition and the 38 wells we have placed on production since the secondfirst quarter of 2016, partially offset by normal well2018, our production decline. In addition, the acreage we acquired from Silverback has shown a higher gas/oil ratio, and therefore our aggregate production iswas made up of a higher percentage of42% natural gas and NGL volumes duringconsistent with 43% in the secondfirst quarter of 2017 (41%) as compared to the second quarter of 2016 (31%).2017.
In addition to production-related increases in net revenue between periods, there were also significant increases in our average realized sales prices for oil natural gas and NGLs in the secondfirst quarter of 20172018 compared to the same 20162017 period. OurThe average price for oil before the effects of hedging increased 7%24%, our average price for natural gas beforeand the effects of hedging increased 36% and our average price for NGLs increased 39%20% between periods. Of the 7%24% increase in ourthe average realized oil price, 6%21% of such increase was related to higher average NYMEX crude prices between periods and the remaining 1%3% was attributable to slightly widernarrower oil differentials in the secondfirst quarter of 2017 due to a portion of our oil volumes being trucked while wells awaited connection into nearby pipelines.2018. The 36% increase in our average realized natural gas price was similarly related to higher NYMEX prices between periods (average NYMEX gas prices being 40% higher between periods) which effect was partially offset by slightly wider gas differentials experienced in the second quarter of 2017. Of the overall 39%20% increase in average realized NGL prices between periods the majority of such increase was relatedprimarily attributable to higher average Mont Belvieu spot prices for plant products from second quarter 2016 to secondthe first quarter 2017 and the remaining increase in NGL price was attributable to the fact thatfirst quarter 2018. Conversely, the average realized sales price of natural gas decreased by 17% from first quarter 2017 to first quarter 2018. This decrease was mainly due to wider gas differentials experienced in Augustthe first quarter of 2016 our2018, which were slightly offset by higher NYMEX prices between periods (average NYMEX gas processor began transporting our NGLs to sales points via pipeline rather than trucking them.prices being 1% higher between periods).
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
Successor  Predecessor
Increase/(Decrease)For the Three Months Ended
Increase/(Decrease)
For the Three Months Ended June 30, 2017  For the Three Months Ended June 30, 2016
$
%March 31, 2018
March 31, 2017
$
%
Operating expenses (in thousands):        
Operating costs (in thousands):       
Lease operating expenses$8,273
  $2,597

$5,676

219 %$16,276
 $7,278

$8,998

124 %
Severance and ad valorem taxes4,723
  1,247

3,476

279 %14,173
 3,187

10,986

345 %
Gathering, processing and transportation expenses7,403
  1,459

5,944

407 %13,828
 5,244

8,584

164 %
Production costs per Boe:        
Operating costs per Boe:       
Lease operating expenses$3.06
  $3.64

$(0.58)
(16)%$3.34
 $4.38

$(1.04)
(24)%
Severance and ad valorem taxes1.75
  1.75

—

— %2.91
 1.92

0.99

52 %
Gathering, processing and transportation expenses2.74
  2.05

0.69
 34 %2.84
 3.16

(0.32) (10)%
Lease Operating Expenses.  Our leaseLease operating expenses (“LOE”) for the three months ended June 30, 2017 (Successor)March 31, 2018 increased $5.7$9.0 million compared to the three months ended June 30, 2016 (Predecessor).March 31, 2017. Higher LOE for the secondfirst quarter of 2017 was2018 primarily related to a $4.6an $8.7 million increase associated with a higher well count, 75 gross wells added through (i) successful drilling and (ii) as a result of the Silverback Acquisition, in addition to higher well workover activity between periods. Well workover costs increased by $1.1 million from the second quarter of 2016 to the second quarter of 2017 also in connection with our higher well count. We had 62197 gross operated horizontal wells as of June 30, 2016March 31, 2018 as compared to 137117 gross operated horizontal wells as of June 30, 2017 (which excludes wells addedMarch 31, 2017. The increase in June as awell count was mainly the result of successful drilling activity which added 75 gross operated wells since the GMT Acquisition).first quarter of 2017, as well as successfully executed acquisitions over the past 12 months. Workover activity remained relatively consistent between periods at $2.4 million and $2.1 million for the three months ended March 31, 2018 and 2017, respectively.
Our LOE on a per Boe basis, on the other hand, decreased when comparing the secondfirst quarter of 20172018 to the same 20162017 period. LOE per Boe was $3.06$3.34 for the secondfirst quarter of 2017,2018, which represents a decrease of $0.58$1.04 per Boe (or 16%24%) from the second

first quarter of 2016.2017. This decrease in rate was mainly due to flush production from new wells we drilled and completed over the past 12 months, which has the effect of reducing fixed and semi-variable costs on a per Boe basis.
Severance and Ad Valorem Taxes.  Severance taxes are primarily based on the market value of our production at the wellhead, and ad valorem taxes are generallymainly based on the valuation of our proved developed oil and natural gas propertiesreserves and vary across the different counties in which we operate.the Company operates. Severance and ad valorem taxes for the three months ended June 30, 2017 (Successor)March 31, 2018 increased $3.5$8.2 million (or 279%) compared to the three months ended June 30, 2016 (Predecessor),March 31, 2017, which was primarily due to higher oil, natural gas and NGL revenues between periods. Severance and ad valorem taxes as a percentage of our revenue remained relatively flat between periods at 5.2%total net revenues increased to 7% for the three months ended June 30, 2017March 31, 2018 as compared to 5.3% for the same 2016 period.5% in 2017 due to increased ad valorem taxes of $2.8 million between periods, associated with our higher well count and related higher property values.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended June 30, 2017 (Successor)March 31, 2018 increased $5.9$8.6 million compared to the three months ended June 30, 2016 (Predecessor)March 31, 2017 due to higher natural gas and NGL volumes sold between periods, which in turn resulted in a higher amount of plant processing fees and per unit transportation and gathering costs being incurred between periods.
On a per BOEBoe basis, our GP&T likewise increaseddecreased 10% from $2.05$3.16 for the secondfirst quarter of 20162017 to $2.74$2.84 per Boe for the secondfirst quarter of 2017.2018. This increasedecrease in rate was mainlypartially due to a change in our gas/oil ratio whereby a higherlower percentage of our total production was made up of natural gas and NGL volumes during the secondfirst quarter of 2017,2018, and thus a higher portionlower proportion of our aggregate production during this 20172018 period was subject to gas gathering and transportation charges as well as gas processing fees. However, when our GP&T rate is evaluated based solely onOn a natural gas and NGL volumes basis (i.e. excluding crude oil barrels) sold, such per BOEthe Boe rate remained relatively consistentdecreased only 6% between periods at $6.65 and $6.52to $6.83 from $7.30 for

the secondfirst quarters of 2018 and 2017, and 2016, respectively. This decrease was primarily the result of lower rates on our primary gas contract due to processing rebates received for new wells connected to the plant.
Depreciation, Depletion and Amortization. The following table summarizes our DD&A for the periods indicated: 
Successor  PredecessorFor the Three Months Ended
(in thousands)For the Three Months Ended June 30, 2017  For the Three Months Ended June 30, 2016March 31, 2018
March 31, 2017
Depreciation, depletion and amortization$34,300
  $21,182
$66,010
 $26,160
Depreciation, depletion and amortization per Boe12.70
  29.71
13.57
 15.74
Our DD&A rate can fluctuate as a result of finding and development costs, acquisitions, impairments, as well as changes in proved andreserves or proved developed reserves. For the three months ended June 30, 2017 (Successor),March 31, 2018, DD&A expense amounted to $34.3$66.0 million, an increase of $13.1$39.9 million over the same 2016 period (Predecessor).2017 period. The primary factor contributing to higher DD&A in 20172018 was the increase in overall production volumes between periods, which in turn resulted in $58.9$50.4 million of incremental DD&A expense being incurred during the secondfirst quarter of 2017.2018. This $58.9 million of incremental DD&Aincrease was largely offset, however, by a $45.9$10.5 million reduction in DD&A expense during the second quarter of 2017, that was attributable to significantly lower DD&A rates between periods.
On aDD&A per Boe basis our overall DD&A rate of $12.70was $13.57 for the secondfirst quarter of 2017 was 57% lower than the rate of $29.712018 compared to $15.74 for the same period in 2016.2017. The primary factor contributing to this lower DD&A rate was substantial additions to our proved reserves and proved developed reserves over the past 12 months, particularly in relationrelative to our capitalized drilling and completion costs incurred over that same time period.
Exploration Expense. The following table summarizes our exploration expenses for the periods indicated:  
Successor  PredecessorFor the Three Months Ended
(in thousands)For the Three Months Ended June 30, 2017  For the Three Months Ended June 30, 2016March 31, 2018
March 31, 2017
Equity based compensation expense$667
  $—
Stock-based compensation expense$381
 $240
Dry exploratory well costs221
 —
Geological and geophysical costs1,803
  262
2,845
 941
Exploration expense$2,470
  $262
$3,447
 $1,181
Exploration expense increased $2.2was $3.4 million for the three months ended June 30, 2017 (Successor)March 31, 2018 compared to $1.2 million the same prior year period (Predecessor).period. Exploration includes costsexpense mainly consists of topographical studies, geographical and geophysical (“G&G”) studies, rights of access to properties to conduct those studies,projects, and salaries and other expenses of G&G personnel and consultants.personnel. The period over period increase in exploration expense iswas primarily due to (i) six geologists added to our staff since the second quarterincreased G&G projects and seismic studies of 2016, and (ii) equity-based compensation awards that were granted to G&G personnel in 2017 and latter 2016 that were not likewise granted as of June 30, 2016.$1.9 million.
General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:  

Successor  PredecessorFor the Three Months Ended
(in thousands)For the Three Months Ended June 30, 2017  For the Three Months Ended June 30, 2016March 31, 2018
March 31, 2017
Equity based compensation expense$2,318
  $—
Stock-based compensation expense$3,952
 $2,370
Cash general and administrative expenses8,323
  2,607
10,345
 8,514
General and administrative expenses$10,641
  $2,607
$14,297
 $10,884
G&A expenses for the three months ended June 30, 2017 (Successor) increased $8.0March 31, 2018 were $14.3 million overcompared to $10.9 million for the same 2016 period (Predecessor). This increase wasfirst quarter of 2017. The higher G&A expenses incurred in 2018 were primarily due to $4.3$1.8 million in increased employee salaries and payroll burdens and $1.6 million in higher employee salaries and related costs between periods, $2.3 million of stock-based compensation incurred duringcompared to the second quarter of 2017 versus none in the same prior year period, and $1.1 million in increased professional fees. Employee-related costsperiod. G&A expenses were substantially higher during the secondfirst quarter of 20172018 due to the number of administrative employees (i.e. non-billable to our joint interest partners) increasing from 28 at June 30, 201662 as of March 31, 2017 to 80 at June 30, 2017, and professional fees were also higher due to costs associated with being a public company that were incurred during the 2017 period.102 as of March 31, 2018.

Other Income and Expenses.
Interest Expense. The following table summarizes our other income and expensesinterest expense for the periods indicated:
 Successor  Predecessor
(in thousands)For the Three Months Ended June 30, 2017  For the Three Months Ended June 30, 2016
Other income (expense)    
Gain on sale of oil and natural gas properties$7,191
  $—
Interest expense(707)  (1,798)
Net gain (loss) on derivative instruments2,529
  (7,843)
Other income$—
  $6
Total other income (expense)$9,013
  $(9,635)
Income tax (expense) benefit$(9,069)  $406
Gain on Sale
 For the Three Months Ended
(in thousands)March 31, 2018 March 31, 2017
Credit facility$784
 $317
Senior Notes5,374
 —
Amortization of debt issuance costs379
 93
Interest capitalized(724) —
Total$5,813
 $410
Interest expense was $5.4 million higher in the first quarter of Oil and Natural Gas Properties. For the three months ended June 30, 2017 (Successor), we recorded a gain on sale of oil and natural gas properties of $7.1 million related2018 compared to the salefirst quarter of our Pecos County, Texas acreage.
Interest Expense. For the three months ended June 30, 2017 (Successor), we recorded $0.72017. This increase was primarily attributable to $5.4 million in interest related to CRP’s credit facility. Forincurred on the three months ended June 30, 2016 (Predecessor), we recorded $0.8 million inSenior Notes versus no interest related to CRP’s credit facility and $1.0 million in interest related to CRP’s term loan that was extinguished upon the closing of the Business Combination. Our weighted average debt outstandingbeing incurred during the second quarter of 2017 was $28.6 million versus $98.7 million forsame prior year period as the second quarter of 2016. Our weighted average effective cash interest rate was 3.52% during the second quarter of 2017 compared to 2.69% for the second quarter of 2016.Senior Notes were issued in November 2017.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of i)(i) fluctuations in mark-to-market derivative fair values associated with corresponding changes in underlying commodity prices.prices and ii)(ii) monthly cash settlements of our hedged derivative positions. For the three months ended June 30,March 31, 2018 and 2017, (Successor), we recognized non-cash mark-to-market derivative gains of $2.2$7.5 million and $4.2 million, respectively. Cash derivative settlements amounted to $0.4 million of gains for the three months ended June 30, 2016 (Predecessor), we recognized non-cash mark-to-marketMarch 31, 2018 compared to $0.4 million of losses of $13.8 million. Cash derivative settlements, on the other hand, amounted to $0.3 million and $6.0 million in gains for the second quarters of 2017 and 2016, respectively.same period in 2017.
Income Tax Expense. During the three months ended June 30, 2017 (Successor)March 31, 2018, the Company recognized $9.1$19.1 million in income tax expense. The Companyexpense, while no income tax expense was recognized a tax benefit of $0.4 million infor the three months ended June 30, 2016 (Predecessor)March 31, 2017. There was no income tax expense recognized during the first quarter of 2017 because we were able to release our deferred tax valuation allowance in the amount of $3.5 million, which fully offset our tax expense due based on pre-tax net income.
The enactment of the Jobs Act in December 2017 reduced the corporate tax rate to 21%. The Company's provision for income taxes for the three months ended June 30, 2017March 31, 2018 differed from the amount that would be provided by applying the blended statutory U.S. federal state, and local income tax rate of 36.1%21% to pre-tax income because the Company released $1.6 million of its deferred tax asset valuation allowance in the second quarter of 2017, such that income tax expense of $10.7 million for the three months ended June 30, 2017 was partially offset by the tax benefit associated with the portion of the valuation allowance released resulting in an effective tax rate of 28.1%.
Six Months Ended June 30, 2017 (Successor) Compared to Six Months Ended June 30, 2016(Predecessor)
The following table provides the components of our revenues for the periods indicated, as well as each period’s average prices and production volumes:

 Successor  Predecessor Increase/(Decrease)
 For the Six Months Ended June 30, 2017  For the Six Months Ended June 30, 2016 $ %
Net revenues (in thousands):        
Oil sales$117,416
  $33,587
 $83,829
 250 %
Natural gas sales20,374
  3,088
 17,286
 560 %
NGL sales14,371
  1,793
 12,578
 702 %
Total net revenues$152,161
  $38,468
 $113,693
 296 %
         
Average sales prices:        
Oil (per Bbl)$46.39
  $35.02
 $11.37
 32 %
Effect of derivative settlements on average price (per Bbl)0.05
  15.30
 (15.25) (100)%
Oil net of hedging (per Bbl)$46.44
  $50.32
 $(3.88) (8)%
         
Average NYMEX price for oil (per Bbl)$50.05
  39.69
 10.36
 26 %
         
Natural gas (per Mcf)$2.83
  $1.97
 $0.86
 44 %
Effect of derivative settlements on average price (per Mcf)(0.04)  —
 (0.04) 100 %
Natural gas net of hedging (per Mcf)$2.79
  $1.97
 $0.82
 42 %
         
Average NYMEX price for natural gas (per Mcf)$3.10
  2.11
 0.99
 47 %
         
NGL (per Bbl)$22.81
  $12.03
 $10.78
 90 %
         
Net production:        
Oil (MBbls)2,531
  959
 1,572
 164 %
Natural gas (MMcf)7,205
  1,567
 5,638
 360 %
NGLs (MBbls)630
  149
 481
 323 %
Total (MBoe) (1)4,362
  1,369
 2,993
 219 %
         
Average daily net production volume:        
Oil (Bbls/d)13,982
  5,269
 8,713
 165 %
Natural gas (Mcf/d)39,807
  8,610
 31,197
 362 %
NGLs (Bbls/d)3,481
  819
 2,662
 325 %
Total (Boe/d) (1)24,097
  7,523
 16,574
 220 %
(1)Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
Oil, Natural Gas and NGL Sales Revenues. Our total net revenues for the first half of 2017 (Successor) were $113.7 million (or 296%) higher than total net revenues for the first half of 2016 (Predecessor). Our revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Our net production volumes for oil, natural gas, and NGLs increased 164%, 360% and 323%, respectively, between periods. The oil volume increase between periods resulted primarily from our drilling success in the Delaware Basin, as well as the addition of producing properties we acquired in the Silverback Acquisition. The Silverback Acquisition, which closed on December 28, 2016, added 371 MBbls of net oil production to our six months ended June 30, 2017 results. In addition, we have placed 38 operated wells on production in the Delaware Basin since the second quarter of 2016, which has added 1,479 MBbls of net oil production to the first six months of 2017. These oil volume increases were partially offset by normal production declines across several of our existing wells. Our natural gas and NGLs are produced concurrently with our crude oil volumes, resulting in a high correlation between fluctuations in our oil quantities sold and our natural gas and NGL quantities sold. Thus, the reasons that our natural gas and NGL sales volumes have increased significantly between periods similarly relate to the Silverback Acquisition and the 38 wells we have placed on production since the second quarter of 2016, partially offset by normal well

production decline. In addition, the acreage we acquired from Silverback has shown a higher gas/oil ratio, and therefore our aggregate production is made up of a higher percentage of natural gas and NGL volumes during the first six months of 2017 (42%) as compared to the first half of 2016 (30%).
In addition to production-related increases in net revenue between periods, there were also significant increases in our average realized sales prices for oil, natural gas and NGLs when comparing the first six months of 2017 to the same 2016 period. Our average price for oil before the effects of hedging increased 32%, our average price for natural gas before the effects of hedging increased 44%, and our average price for NGLs increased 90% between periods. Of the 32% increase in our average realized oil price, 26% of such increase was related to higher average NYMEX crude prices between periods, and the remaining 6% was attributable to wider oil differentials in the second half of 2017 due to a portion of our oil volumes being trucked while wells awaited connection into nearby pipelines. The 44% increase in our average realized natural gas price was similarly related to higher NYMEX prices between periods (NYMEX natural gas prices being up 47% between periods) which effect was partially offset by wider gas differentials experienced in the first half of 2017. Of the overall 90% increase in average realized NGL prices between periods, the majority of such increase was related to higher average Mont Belvieu spot prices for plant products from the first half of 2016 to the first half of 2017, and the remaining increase in NGL price was attributable to the fact that in August of 2016 our gas processor began transporting our NGLs to sales points via pipeline rather than trucking them.
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
 Successor  Predecessor Increase/(Decrease)
 For the Six Months Ended June 30, 2017  For the Six Months Ended June 30, 2016 $ %
Operating Expenses (in thousands):        
Lease operating expenses$15,551
  $6,639
 $8,912
 134 %
Severance and ad valorem taxes7,910
  2,091
 5,819
 278 %
Gathering, processing and transportation expenses12,647
  2,589
 10,058
 388 %
Production costs per Boe:        
Lease operating expenses$3.57
  $4.85
 $(1.28) (26)%
Severance and ad valorem taxes1.81
  1.53
 0.28
 18 %
Gathering, processing and transportation expenses2.90
  1.89
 1.01
 53 %
Lease Operating Expenses. Our LOE for the six months ended June 30, 2017 (Successor) increased $8.9 million compared to the first six months of 2016 (Predecessor). Higher LOE for the first half of 2017 was primarily related to a $6.6 million increase associated with a higher well count, 75 gross wells added through (i) successful drilling and (ii) as a result of the Silverback Acquisition, in addition to higher well workover activity between periods. Well workover costs increased by $2.3 million from the first half of 2016 to the first half of 2017 also in connection with our higher well count. We had 62 gross operated horizontal wells as of June 30, 2016 as compared to 137 gross operated horizontal wells as of June 30, 2017 (which excludes wells added in June as a result of the GMT Acquisition).
Our LOE on a per Boe basis, on the other hand, decreased when comparing the first six months of 2017 to the same 2016 period. LOE per Boe was $3.57 for the six months ended June 30, 2017, which represents a decrease of $1.28 per Boe (or 26%) from the first six months of 2016. This decrease in rate was mainly due to flush production from new wells we drilled and completed over the past 12 months, which has the effect of reducing fixed and semi-variable costs on a per Boe basis.
Severance and Ad Valorem Taxes. Severance taxes are primarily based on the market value of our production at the wellhead, and ad valorem taxes are generally based on the valuation of our oil and natural gas properties and vary across the different counties in which we operate. Severance and ad valorem taxes for the six months ended June 30, 2017 (Successor) increased $5.8 million (or 278%) compared to the first six months of 2016 (Predecessor) which was primarily due to higher oil, natural gas and NGL revenues between periods. Severance and ad valorem taxes as a percentage of our revenue remained relatively consistent at 5.2% for the six months ended June 30, 2017 compared to 5.4% for the same 2016 period.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) for the six months ended June 30, 2017 (Successor) increased $10.1 million compared to the first six months of 2016 (Predecessor) due to higher natural gas and NGL volumes sold between periods, which in turn resulted in a higher amount of plant processing fees and per unit transportation and gathering costs being incurred between periods. On a per BOE basis, our GP&T likewise increased from $1.89 for the first half of 2016 to $2.90 per Boe for the six months ended June 30, 2017. This increase in rate was mainly attributable to the change in our gas/oil ratio whereby a higher percentage of our total production was made up of natural gas and NGL volumes during the first half of 2017, and thus a higher portion of our aggregate production during this 2017 period was subject to gas gathering and transportation charges as well as gas processing fees. However, when our GP&T rate is evaluated

based solely on natural gas and NGL production (i.e. excluding crude oil barrels) sold, such per BOE rate only increased slightly between periods from $6.31 to $6.91 for the first six months of 2016 and 2017, respectively.
Depreciation, Depletion, and Amortization. The following table summarizes our DD&A for the periods indicated: 
 Successor  Predecessor
(in thousands)For the Six Months Ended June 30, 2017  For the Six Months Ended June 30, 2016
Depreciation, depletion and amortization$60,460
  $42,485
Depreciation, depletion and amortization per Boe13.86
  31.03
Our DD&A rate can fluctuate as a result of finding and development costs, acquisitions, impairments, as well as changes in proved and proved developed reserves. For the six months ended June 30, 2017 (Successor), DD&A expense amounted to $60.5 million, an increase of $18.0 million over the same 2016 period (Predecessor). The primary factor contributing to higher DD&A in 2017 was the increase in overall production volumes between periods, which in turn resulted in $92.7 million of incremental DD&A expense being incurred during the first half of 2017. This $92.7 million of incremental DD&A was largely offset by a $74.9 million reduction in DD&A expense during the first six months of 2017, that was attributable to significantly lower DD&A rates between periods.
On a Boe basis our overall DD&A rate of $13.86 for the first six months of 2017 was 55% lower than the rate of $31.03 for the same period in 2016. The primary factor contributing to this lower DD&A rate was substantial additions to our proved and proved developed reserves over the past 12 months, particularly in relation to our capitalized drilling and completion costs incurred over that same time period.
Exploration Expense. The following table summarizes our exploration expenses for the periods indicated: 
 Successor  Predecessor
(in thousands)For the Six Months Ended June 30, 2017  For the Six Months Ended June 30, 2016
Equity based compensation expense$667
  $—
Geological and geophysical costs1,803
  517
Exploration expense$2,470
  $517
Exploration increased $2.0 million for the six months ended June 30, 2017 (Successor) compared to the same prior year period (Predecessor). Exploration includes costs of topographical, G&G studies, rights of access to properties to conduct those studies, and salaries and other expenses of G&G personnel and consultants. The period over period increase in exploration expense is due to (i) six geologists added to our staff since the second quarter of 2016, and (ii) equity-based compensation awards that were granted to G&G personnel in 2017 and latter 2016 that were not likewise granted as of June 30, 2016.
General and Administrative Expenses. The following table summarizes our G&A expenses for the periods indicated: 
 Successor  Predecessor
(in thousands)For the Six Months Ended June 30, 2017  For the Six Months Ended June 30, 2016
Equity based compensation expense$4,928
  $—
Cash general and administrative expenses17,778
  4,888
General and administrative expenses$22,706
  $4,888
G&A expenses for the six months ended June 30, 2017 (Successor) increased $17.8 million over the same 2016 period (Predecessor). This increase was primarily due to $8.8 million in higher employee salaries and related costs between periods, $4.9 million of stock-based compensation incurred during the first half of 2017 versus none in the same prior year period, $0.8 million of one-time G&A costs related to the Silverback Acquisition, and $2.1 million in increased professional fees. Employee-related costs were substantially higher during the first half of 2017 due to the number of administrative employees (i.e. non-billable to our joint interest partners) increasing from 28 at June 30, 2017 to 80 as of June 30, 2017, and professional fees were also higher due to costs associated with being a public company that were incurred during the 2017 period.
Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:

 Successor  Predecessor
(in thousands)For the Six Months Ended June 30, 2017  For the Six Months Ended June 30, 2016
Other income (expense):    
Gain (loss) on sale of oil and natural gas properties7,357
  (4)
Interest expense$(1,117)  $(3,439)
Net gain (loss) on derivative instruments6,288
  (5,925)
Other income—
  6
Total other income (expense)$12,528
  $(9,362)
Income tax (expense) benefit$(9,069)  $406
Gain on Sale of Oil and Natural Gas Properties. In the first half of 2017 (Successor), we recorded a gain on sale of oil and natural gas properties of $7.1 million related to the sale of our Pecos County, Texas acreage.
Interest Expense. For the six months ended June 30, 2017 (Successor), we recorded $1.1 million in interest related to CRP’s credit facility. For the six months ended June 30, 2016 (Predecessor), we recorded $1.3 million in interest related to CRP’s credit facility and $2.1 million on the term loan that was extinguished upon closing of the Business Combination. Our weighted average debt outstanding for the first six months of 2017 was $14.4 million versus $87.1 million for the first six months of 2016. Our weighted average effective cash interest rate was 3.52% during the first half of 2017 compared to 2.59% for the first half of 2016.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of i) fluctuations in mark-to-market derivative fair values associated with corresponding changes in underlying commodity prices. and ii) monthly cash settlements of our hedged derivative positions. For the six months ended June 30, 2017 (Successor), we recognized non-cash mark-to-market derivative gains of $6.4 million, and for the six months ended June 30, 2016 (Predecessor), we recognized non-cash mark-to-market losses of $20.6 million. Cash derivative settlements, on the other hand, amounted to $0.1 million in losses and $14.7 million in gains for the first six months of 2017 and 2016, respectively.
Income Tax Expense. During the six months ended June 30, 2017 (Successor) the Company recognized $9.1 million income tax expense. The Company recognized a tax benefit of $0.4 million in the six months ended June 30, 2016 (Predecessor). The Company's provision forstate income taxes for the six months ended June 30, 2017 differed from the amount that would be provided by applying the blended statutory U.S. federal, state, and local income tax rate of 36.1% to pre-tax income because the Company released $5.1 million of its deferred tax asset valuation allowance in the first half of 2017, such that income tax expense of $14.2 million for the six months ended June 30, 2017 was partially offset by the tax benefit associated with the portion of the valuation allowance released resulting in an effective tax rate of 21.1%.

permanent differences.

Liquidity and Capital Resources
Overview
Our developmentdrilling and completion and land acquisition activities require us to make significant operating and capital expenditures. Historically, our primary sources of liquidity have been borrowings under CRP’s revolving credit facility, cash flows from operations and proceeds from asset dispositionsofferings of debt and prior to the Business Combination, capital contributions from CRP’s equity sponsors.securities. To date, our primary use of capital has been for thedevelopment and acquisition and development of oil and natural gas properties.
The following table summarizes our capital expenditures incurred for the sixthree months ended June 30, 2017:March 31, 2018:
(in millions)Six Months Ended June 30, 2017For the Three Months Ended March 31, 2018
Drilling and completion capital expenditures$235.1
$181.8
Land and other26.3
Facilities, seismic and other9.0
Facilities, infrastructure and other (1)
50.2
Land6.3
Total capital expenditures270.4
$238.3
(1)
Facilities, infrastructure and other includes $38.8 million of well-level facility costs. In previous reporting periods, these costs were presented within drilling and completion capital expenditures. This presentation change was made in order to conform our drilling and completion capital expenditures to that of our peer group and to also present costs consistently with our 2018 capital expenditure budget.
We continually evaluate our capital needs and compare them to our capital resources. Our estimated capital expenditure budget for 20172018 is $535.0$885 million to $625.0$1,050 million, of which we$710 million to $820 million is related to drilling and completion (“D&C”) activity. We expect to fund our capital expenditure budget with cash flows from operations and borrowings under our credit facility. The drilling and completion (“D&C”)&C portion of our 20172018 capital budget represents a significantan increase over the $97.7$624.1 million of D&C expenditures incurred during 2016.2017. This increased 2018 capital budget is driven by an increase in responserig activity from six to seven rigs, the higher level of anticipated cash flowsassociated increase in wells to be generated from (i) new wells we drilled in 2018 versus 2017, and completed in latter 2016 and plan to drill in 2017, (ii) wells we addedthe increase in the Silverback Acquisition and GMT Acquisition and (iii) higher crude oil and natural gas prices experienced during the fourth quarternumber of 2016 and continuing into 2017, as well as our strong balance sheet position with minimal borrowings outstanding as of June 30, 2017.extended lateral wells to be drilled which require more capital than shorter laterals.
Because we are the operator of a high percentage of our acreage, we are able to control the amount and timing of these capital expenditures are largely discretionary.expenditures. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities,activities; prevailing and anticipated prices for oil and natural gas,gas; the availability of necessary equipment, infrastructure and capital,capital; the receipt and timing of required regulatory permits and approvals,approvals; seasonal conditions,conditions; drilling and acquisition costscosts; and the level of participation by other working interest owners.
Based upon current oil and natural gas price expectations for the remainder of 2017,2018, we believe that our cash flow from operations and borrowings under CRP’s revolvingour credit facility will provide us with sufficient liquidity to execute our current capital program. However, our future cash flows are subject to a number of variables, including the future level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot ensure that operations and other needed capital will be available on acceptable terms or at all. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital.sources for funding capital investments. As we pursue our future development program, we are actively assessing the correct mix of reserve-based borrowings and debt offerings. If we require additional capital for that or other reasons,to fund acquisitions, we may also seek such capital through traditional reserve basereserve-based borrowings, asset sales, offerings of debt and equity securities, asset sales or other means. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.
Working Capital Analysis
Our cash balances were zero and $134.1 million as of June 30, 2017 and December 31, 2016, respectively. Due to the amounts that accrue related to our drilling program, we may incur temporary working capital deficits. However, we expect that our cash flows from operating activities and availability under CRP’s credit agreement will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.
Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2017 (Successor) and June 30, 2016(Predecessor)
The following table summarizes our cash flows for the periods indicated:

Successor  PredecessorFor the Three Months Ended
(in thousands)For the Six Months Ended June 30, 2017  For the Six Months Ended June 30, 2016March 31, 2018 March 31, 2017
Net cash provided by operating activities$93,140
  $35,604
$131,826
 $19,248
Net cash used in investing activities(595,325)  (85,455)(218,583) (98,420)
Net cash provided by financing activities368,102
  48,767
Net cash used in financing activities(934) (37)

During the first half of 2017,three months ended March 31, 2018, we generated $93.1$131.8 million of cash provided by operating activities, an increase of $57.5$112.6 million from the same period in 2016.2017. Cash provided by operating activities increased primarily due to higher net income between periods as a results of increased crude oil, natural gas and NGL production volumes;volumes and higher realized sales prices for crude oil natural gas and NGLs; and lower cash interest during the first half of 2017.NGLs. These positive factors were partially offset by a decrease in cash settlements received on our derivative contracts, as well as higher lease operating expenses, severance and ad valorem taxes, GP&T expenses, exploration costs, and cash G&A expenses and interest paid during the first half of 2017three months ended March 31, 2018 as compared to the same period in 2016.2017. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for more information on increases and decreases in certain expenses between periods.
During the first halfthree months ended March 31, 2018, cash flows from operating activities, cash on hand and proceeds from sales of oil and natural gas properties were used to finance $250.5 million of drilling and development expenditures and $101.8 million in oil and gas property acquisitions.
During the three months ended March 31, 2017, cash flows from operating activities and cash on hand were used to finance $198.3$62.1 million of drilling and development expenditures while $333.5 million in net proceeds from the issuance of Class A common shares together with cash on hand, $35.0 in net borrowings under our credit facility, and proceeds from the sale of oil and gas properties were used to finance $405.2$38.7 million in oil and gas property acquisitions.
Revolving Credit FacilityAgreement
OurCRP, the Company’s consolidated subsidiary, CRP has a revolving credit agreement with a syndicate of banks that as of June 30, 2017March 31, 2018, had a borrowing base of $350.0$575.0 million which has been committedand elected commitments of $475.0 million. This aggregate commitment by our lenders and is available to the Company for borrowing. A portion of the revolving credit facility in an aggregate amount not to exceed $15.0 million may be used to issue letters of credit for the account of CRP or other designated subsidiaries of the Company. As of June 30, 2017, the CompanyMarch 31, 2018, CRP had $314.1no borrowings outstanding and $474.1 million in available borrowing capacity, which was net of $35.0 million in borrowings and $0.9 million in letters of credit outstanding.
The amount available to be borrowed under CRP'sCRP’s revolving credit facility is subject to a borrowing base that is redetermined semiannuallysemi-annually each April 1 and October 1 by the lenders in their sole discretion. CRP'sCRP’s credit agreement also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the volumesquantities of CRP'sCRP’s proved oil and natural gas reserves, and estimated cash flows from these reserves and itsthe Company’s commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if actual borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under itsthe credit agreement. TheBorrowings under CRP’s revolving credit facility provides for interest only payments until October 2019, when the credit agreement expires and all outstanding borrowings are due.guaranteed by certain of its subsidiaries.
Borrowings under CRP’s revolving credit facility may be base rate loans or LIBOR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for LIBOR loans. LIBOR loans bear interest at LIBOR (adjusted for statutory reserve requirements) plus an applicable margin ranging from 225 to 325 basis points, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points, plus an applicable margin ranging from 125 to 225 basis points, depending on the percentage of the borrowing base utilized. At June 30, 2017, the weighted average interest rate on borrowings under CRP’s revolving credit facility was approximately 3.35%. CRP also pays a commitment fee on unused amounts ofunder its revolving credit facility of 50 basis points. CRP may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.
CRP’s credit agreement contains restrictive covenants that limit its ability to, among other things: incur additional indebtedness; make investments and loans; enter into mergers; make or declare dividends; enter into commodity hedges exceeding a specified percentage of our expected production; enter into interest rate hedges exceeding a specified percentage of ourits outstanding indebtedness; incur liens; sell assets; and engage in transactions with affiliates.
CRP’s credit agreement also requires it to maintain compliance with the following financial ratios: (1)(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 under Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) Topic 815, Derivatives and Hedging and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under ourthe credit agreement and non-cash liabilities under ASC 815)derivative liabilities), of not less than 1.0 to 1.0; and (2)(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 thethese covenants and the financial ratios described above as of June 30, 2017March 31, 2018 and through the filing of this report.Quarterly Report.
Off-Balance Sheet ArrangementsOn May 4, 2018, the Company entered into the Amended Agreement with a majority of the 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 elected commitments increased from $475.0 million to $600.0 million. The credit facility under the Amended Agreement has a term of five years.
AsThe Amended Agreement has interest rate and utilization fee structure similar to the existing credit agreement described above. However, the Amended Agreement provides for lower rates and fees, which vary depending on the percentage of Junethe 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 or 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.
5.375% Senior Unsecured Notes due 2026
On November 30, 2017, we had no off-balance sheet arrangements.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 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 March 31, 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.
Contractual Obligations
The Company’s contractual obligations include drilling rig commitments, office leases, water disposal agreements, purchase obligations, asset retirement obligations, long-term debt obligations, cash interest expense on long-term debt obligations and transportation and gathering agreements. Since December 31, 2017, there have not been any significant, non-routine changes in our contractual obligations, other than an additional transportation agreement as discussed in Note 12—Commitments and Contingencies under Part I, Item 1. of this Quarterly Report.
Critical Accounting Policies and Estimates
There have been no material changes during the sixthree months ended June 30, 2017March 31, 2018 to the methodology applied by management for critical accounting policies previously disclosed in our 20162017 Annual Report. Please refer to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates in our 20162017 Annual Report for a discussion of our critical accounting policies and estimates.

New Accounting Pronouncements
Please refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies under Part I, Item 1. of this quarterly reportQuarterly Report for a discussion of the effects of recently adopted accounting standards and the potential effects of new accounting matters.pronouncements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk includingin the effectsform of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” as it applies to our business refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLsNGL production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. Based on our production for the first three months of 2018, our income before income taxes for the three months ended March 31, 2018 would have moved up or down $17.5 million for each 10% change in oil prices per Bbl, $2.2 million for each 10% change in NGL prices per Bbl and $1.9 million for each 10% change in natural gas prices per Mcf.
Due to this volatility, we have historically used, and we expectmay elect to continue to opportunisticallyselectively use, commodity derivative instruments, such as collars, swaps, collars and basis swaps, to hedgemitigate price risk associated with a portion of our anticipated production. Our hedgingderivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flowflows from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices and may partially limit our potential gains from future increases in prices. CRP’sOur credit agreement limits itsour ability to enter into commodity hedges covering greater than 80% of itsour reasonably anticipated projected production volume.from proved properties.
OurThe following table summarizes the terms of the swap contracts the Company had in place as of March 31, 2018 and additional contracts entered into through May 1, 2018. Refer to Note 7—Derivative Instruments in Item 1 of Part I of this Quarterly Report for open derivative positions as of June 30, 2017:March 31, 2018:
Description & Production PeriodVolume (Bbl) Weighted Average Fixed Price ($/Bbl) (1)
Crude Oil Swaps:   
July 2017 - December 201746,000
 $64.05
July 2017 - December 201718,400
 54.65
July 2017 - December 201718,400
 43.50
July 2017 - December 201718,400
 44.85
July 2017 - December 201718,400
 45.10
July 2017 - December 201755,200
 44.80
July 2017 - December 201718,400
 47.27
July 2017 - December 201718,400
 49.00
July 2017 - December 201792,000
 49.80
July 2017 - December 201736,800
 52.35
January 2018 - December 201836,500
 55.95
Crude Oil Basis Swaps:   
July 2017 - November 201736,958
 $(0.20)
July 2017 - November 201714,784
 (0.20)
Description and Production PeriodVolume (Bbl) 
Weighted Average Differential ($/Bbl) (1)
Crude Oil Basis Swaps:   
April 2018 - June 201891,000
 $0.10
April 2018 - June 201891,000
 0.20
April 2018 - June 201891,000
 0.20
April 2018 - June 201891,000
 0.22
April 2018 - June 201891,000
 0.17
April 2018 - December 2018137,500
 0.00
April 2018 - December 2018137,500
 0.00
April 2018 - December 2018550,000
 0.00
April 2018 - December 2018275,000
 0.00
April 2018 - December 2018275,000
 0.00
May 2018 - March 2019760,000
 (5.25)
May 2018 - March 2019190,000
 (5.25)
June 2018 - March 2019174,500
 (5.50)
June 2018 - March 2019349,000
 (5.50)
 
(1)
The oil basis swap contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis derivative contractstransactions are settled based on the difference between the arithmetic average of the ARGUS MIDLAND WTI MIDLANDand ARGUS and WTI ARGUSCUSHING settlements, during the relevant calculation period.


Description & Production PeriodVolume (MMBtu) Weighted Average Fixed Price ($/MMBtu) (1)
Natural Gas Swaps:   
July 2017 - December 2017736,000
 $2.94
Description and Production PeriodVolume (MMBtu) 
Weighted Average Fixed Price ($/MMBtu)(1)
Natural Gas Swaps:   
January 2019 - December 20193,650,000
 $2.78
January 2019 - December 20193,650,000
 2.78
January 2019 - December 20193,650,000
 2.78
    
Description and Production PeriodVolume (MMBtu) 
Weighted Average Differential ($/MMBtu)(2)
Natural Gas Basis Swaps:   
April 2018 - December 20181,375,000
 $(0.43)
January 2019 - December 20191,825,000
 $(0.43)
January 2019 - December 20193,650,000
 $(1.46)
January 2019 - December 20193,650,000
 $(1.46)
January 2019 - December 20193,650,000
 $(1.47)
 
(1)
The natural gas derivativeswap contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas.
(2)
The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and the NYMEX price of Natural Gas during the relevant calculation period.
TheChanges in the fair value of these commodity derivative instruments at June 30,contracts from December 31, 2017 was a net asset of $1.5 million. to March 31, 2018, are presented below:
(in thousands) Commodity derivative contracts
Net fair value of oil and gas derivative contracts outstanding as of December 31, 2017 $855
Contracts settled (399)
Change in the futures curve of forecasted commodity prices 7,880
Contracts added —
Net fair value of oil and gas derivative contracts outstanding as of March 31, 2018 $8,336
A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of June 30, 2017March 31, 2018 would cause a $1.8$0.5 million increase or decrease, respectively, in this fair value liability,asset, and a hypothetical upward or downward shift of 10% per Mcf in the NYMEX forward curve for natural gas as of June 30, 2017March 31, 2018 would cause a $0.2$0.4 million increase or decrease, respectively, in this fair value liability.

asset.
Interest Rate Risk
At June 30, 2017, we had $35.0 million of debt outstanding, with a weighted averageThe Company’s ability to borrow and the rates offered by lenders can be adversely affected by deteriorations in the credit markets and/or downgrades in the Company’s credit rating. CRP’s credit facility interest rate of 3.35%. Interest is calculated under the terms of CRP’s credit agreement based on a LIBOR spread. Assuming no change inspread, which exposes the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the assumed weighted averageCompany to interest rate would be approximately $0.4 million per year.risk if we have borrowings outstanding. At March 31, 2018, the Company had no borrowings outstanding under its credit facility. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.
The Company’s long-term debt balance of $390.9 million consists of our Senior Notes, which has a fixed interest rate; therefore, this balance is not affected by interest rate movements. For additional information regarding the Company’s debt instruments, see Note 4—Long-Term Debt, in Item 1 of Part I of this Quarterly Report.



Item 4. Controls and Procedures
Evaluation of Disclosure Control and Procedures
In accordance with Rules 13a-15 and 15d-15 under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2017.March 31, 2018. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2017March 31, 2018 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There have not been any changes in our internal control over financial reporting that occurred during the three months ended June 30, 2017March 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.



PART II.  OTHER INFORMATION

Item 1. Legal Proceedings.
From time to time, we are party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment related disputes. While the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.
Item 1A. Risk Factors.
In addition to the other information set forth in this report,Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our 2017 Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Annual Report”) and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our businesses, financial condition, or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or future results. There have been no material changes in our risk factors from those described in our 20162017 Annual Report or our other SEC filings.
Item 6. Exhibits.
Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior SEC filing as indicated.
Exhibit
Number		 Description of Exhibit
2.1Purchase and Sale Agreement, dated April 28, 2017, between GMT Exploration Company LLC and Centennial Resource Production, LLC (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 1, 2017).
3.1 
Second Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on October 11, 2016).
3.2 
Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on October 7, 2016).
3.3 
Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC dated as of October 11, 2016 (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed with the SEC on October 11, 2016).
3.4 
Amendment No. 1 to Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC dated as of December 28, 2016 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on December 29, 2016).
3.5 
Amendment No. 2 to Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC dated as of March 20, 2017 (incorporated by reference to Exhibit 3.5 to the Registrant’s Annual Report on Form 10-K filed with the SEC on March 23, 2017).
10.1 Fourth Amendment to
Second Amended and Restated Credit Agreement, dated as of April 28, 2017, by andMay 4, 2018, among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and guarantors party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 1, 2017)7, 2018).
10.210.2*# Form of Subscription Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 5, 2017).
Centennial Resource Development, Inc. Non-Employee Director Compensation Program.
31.1* 
Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2* 
Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1* 
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
32.2* 
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
101.INS* XBRL Instance Document.
101.SCH* XBRL Taxonomy Extension Schema Document.
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB* XBRL Taxonomy Extension Label Linkbase Document.
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document.
#    Management contract or compensatory plan or agreement.
*    Filed herewith.



SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.
 CENTENNIAL RESOURCE DEVELOPMENT, INC.
   
 By:/s/ GEORGE S. GLYPHIS
  
George S. Glyphis
Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer)
   
 Date:AugustMay 8, 20172018


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