Permian Resources - 10-Q quarterly report FY2017 Q2

Permian Resources - 10-Q quarterly report FY2017 Q2

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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, 2017

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

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, there were 256,670,839 shares of Class A Common Stock, par value $0.0001 per share and 19,155,921 shares of Class C Common Stock, par value $0.0001 per share, outstanding.

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		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

Item 1.	Financial Statements (Unaudited)

	Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016	8

	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2017 and 2016	9

	Condensed Consolidated Statement of Shareholders’ Equity for the Six Months Ended June 30, 2017	10

	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2017 and 2016	11

	Notes to Condensed Consolidated Financial Statements	12

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37

Item 4.	Controls and Procedures	39

Part II—OTHER INFORMATION		40

Item 1.	Legal Proceedings	40

Item 1A.	Risk Factors	40

Item 6.	Exhibits	40

Signatures		41

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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/d. One Bbl per day.

Boe. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Boe/d. One Boe per day.

Btu. One British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Completion. Installation of permanent equipment for production of oil or natural gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Development project. The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

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.

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.

NGLs. Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

NYMEX. The New York Mercantile Exchange.

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Operator. The individual or company responsible for the development and/or production of an oil or natural gas well or lease.

Proved reserves. The estimated quantities of oil, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Realized price. The cash market price less all expected quality, transportation and demand adjustments.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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

Spot market price. The cash market price without reduction for expected quality, transportation and demand adjustments.

Working interest. The right granted to the lessee of a property to develop and produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

WTI. West Texas Intermediate.

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GLOSSARY OF CERTAIN OTHER TERMS

The following are definitions of certain other terms that are used in this Quarterly Report on Form 10-Q:

Business Combination. The acquisition of approximately 89% of the outstanding membership interests in CRP from the Centennial Contributors, which closed on October 11, 2016, and the other transactions contemplated by the Contribution Agreement.

Celero. Celero Energy Company, LP, a Delaware limited partnership.

Centennial Contributors. CRD, NGP Follow-On and Celero, collectively.

The Company, we, our or us. (i) Centennial Resource Development, Inc. and its 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. Our acquisition of certain undeveloped acreage and producing oil and natural gas properties of GMT Exploration Company LLC, which closed on June 8, 2017.

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 our Sponsor, collectively.

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. Our 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.

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q 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, 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, the words ”could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016 (our “2016 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;


•	our reserves;


•	our drilling prospects, inventories, projects and programs;


•	our ability to replace the reserves we produce through drilling and property acquisitions;


•	our financial strategy, liquidity and capital required for our development program;


•	our realized oil, natural gas and natural gas liquids (“NGL”) prices;


•	the timing and amount of our future production of oil, natural gas and NGLs;


•	our hedging strategy and results;


•	our future drilling plans;


•	our competition and government regulations;


•	our ability to obtain permits and governmental approvals;


•	our pending legal or environmental matters;


•	our marketing of oil, natural gas and NGLs;


•	our leasehold or business acquisitions;


•	our costs of developing our properties;


•	general economic conditions;


•	credit markets;


•	uncertainty regarding our future operating results; and


•	our plans, objectives, expectations and intentions contained in this Form 10-Q that are not historical.

All forward-looking statements speak only as of the date of this Form 10-Q. 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 2016 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.

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Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-Q 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-Q 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.

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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, 2016
ASSETS
Current assets
Cash and cash equivalents	$	—		$	134,083
Accounts receivable, net	34,809			14,734
Derivative instruments	1,516			431
Prepaid and other current assets	2,431			2,078
Total current assets	38,756			151,326
Oil and natural gas properties, successful efforts method
Unproved properties	2,122,262			1,905,661
Proved properties	1,006,202			605,853
Accumulated depreciation, depletion and amortization	(73,687		)	(14,436)
Total oil and natural gas properties, net	3,054,777			2,497,078
Other property and equipment, net	3,647			2,193
Total property and equipment, net	3,058,424			2,499,271
Noncurrent assets
Derivative instruments	131			—
Other noncurrent assets	1,258			1,045
Total assets	$	3,098,569		$	2,651,642
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses	$	119,508		$	86,100
Derivative instruments	185			5,361
Total current liabilities	119,693			91,461
Noncurrent liabilities
Revolving credit facility	35,000			—
Asset retirement obligations	8,855			7,226
Deferred tax liability	9,069			—
Derivative instruments	—			20
Total liabilities	172,617			98,707
Shareholders’ equity
Preferred stock, $.0001 par value, 1,000,000 shares authorized:
Series A: 1 share issued and outstanding	—			—
Series B: no shares issued and outstanding at 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, 2016	26			20
Class C: 19,155,921 shares issued and outstanding	2			2
Additional paid-in capital	2,700,473			2,364,049
Retained earnings (accumulated deficit)	21,656			(8,929		)
Total shareholders’ equity	2,722,157			2,355,142
Noncontrolling interest	203,795			197,793
Total equity	2,925,952			2,552,935
Total liabilities and shareholders’ equity	$	3,098,569		$	2,651,642

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

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)



	Successor			Predecessor			Successor			Predecessor
	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 revenues
Oil sales	$	70,735		$	20,361		$	117,416		$	33,587
Natural gas sales	12,133			1,775			20,374			3,088
NGL sales	8,196			1,211			14,371			1,793
Total net revenues	91,064			23,347			152,161			38,468
Operating expenses
Lease operating expenses	8,273			2,597			15,551			6,639
Severance and ad valorem taxes	4,723			1,247			7,910			2,091
Gathering, processing and transportation expenses	7,403			1,459			12,647			2,589
Depreciation, depletion and amortization	34,300			21,182			60,460			42,485
Abandonment expense and impairment of unproved properties	—			897			(29		)	897
Exploration expense	2,470			262			2,470			517
General and administrative expenses	10,641			2,607			22,706			4,888
Total operating expenses	67,810			30,251			121,715			60,106
Total operating income (loss)	23,254			(6,904		)	30,446			(21,638		)
Other income (expense)
Gain (loss) on sale of oil and natural gas properties	7,191			—			7,357			(4		)
Interest expense	(707		)	(1,798		)	(1,117		)	(3,439		)
Net gain (loss) on derivative instruments	2,529			(7,843		)	6,288			(5,925		)
Other income	—			6			—			6
Other income (expense)	9,013			(9,635		)	12,528			(9,362		)
Income (loss) before income taxes	32,267			(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	)
Less: Net income attributable to noncontrolling interest	2,436			—			3,320			—
Net income (loss) attributable to common shareholders	$	20,762		$	(16,133	)	$	30,585		$	(30,594	)
Income per share:
Basic	$	0.09					$	0.14
Diluted	$	0.09					$	0.14

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

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (unaudited)

(in thousands)



	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 Equity
	Shares		Amount		Shares	Amount		Shares	Amount		Shares		Amount		Additional Paid-In Capital			(Accumulated Deficit) Retained Earnings			Total Shareholders’ Equity			Noncontrolling Interest		Total Equity
Balance at December 31, 2016	201,092		$	20	19,156	$	2	—	$	—	104		$	—	$	2,364,049		$	(8,929	)	$	2,355,142		$	197,793	$	2,552,935
Warrants exercised	6,236		1		—	—		—	—		—		—		(1		)	—			—			—		—
Restricted stock issued	324		—		—	—		—	—		—		—		—			—			—			—		—
Restricted stock forfeited	(7	)	—		—	—		—	—		—		—		—			—			—			—		—
Conversion of Series B preferred shares to Class A common shares	26,100		3		—	—		—	—		(104	)	—		(3		)	—			—			—		—
Sale of unregistered Class A common shares	23,500		2		—	—		—	—		—		—		340,748						340,750			—		340,750
Underwriters' discount and offering expense	—		—		—	—		—	—		—		—		(7,233		)	—			(7,233		)	—		(7,233		)
Equity based compensation	—		—		—	—		—	—		—		—		5,595			—			5,595					5,595
Change in equity due to issuance of shares by Centennial Resource Production, LLC	—		—		—	—		—	—		—		—		(2,682		)	—			(2,682		)	2,682		—
Net income	—		—		—	—		—	—		—		—		—			30,585			30,585			3,320		33,905
Balance at June 30, 2017	257,245		$	26	19,156	$	2	—	$	—	—		$	—	$	2,700,473		$	21,656		$	2,722,157		$	203,795	$	2,925,952

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

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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 amortization	60,460			42,485
Equity based compensation expense	5,595			—
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 costs	214			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 liabilities	18,434			1,228
Net cash provided by operating activities	93,140			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 properties	10,675			—
Net cash used in investing activities	(595,325		)	(85,455		)
Cash flows from financing activities:
Issuance of Class A common shares	340,750			—
Underwriters discount and offering costs	(7,233		)	—
Proceeds from revolving credit facility	50,000			55,000
Repayment of revolving credit facility	(15,000		)	(5,000		)
Financing obligation	—			(1,233		)
Debt issuance costs	(415		)	—
Net cash provided by financing activities	368,102			48,767
Net decrease in cash and cash equivalents	(134,083		)	(1,084		)
Cash and cash equivalents, beginning of period	134,083			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.

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

The Company’s Class A Common Stock trades on The NASDAQ Capital Market (“NASDAQ”) under the ticker symbol “CDEV.” The Units automatically separated into their component securities prior to or upon closing of the Business Combination and, as a result, no longer trade as a separate security. 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 CRP and its wholly-owned subsidiaries. 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.

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. 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 interim financial statements are adequate, they should be read in conjunction with our 2016 Annual Report.

In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying condensed consolidated financial statements. The 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.

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) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) determining fair value and allocating purchase price in connection with business combinations; (6) valuation of derivative instruments; and (7) accrued revenue and related receivables.

Recently Issued Accounting Standards

In January 2017, 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. Adoption of this standard will only affect 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 still 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 effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. The Company elected to early adopt this guidance in October 2016 in conjunction with the issuance of its equity awards.

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In 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.

In February 2016, the FASB issued ASU 2016-02, Leases. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, 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 update 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, 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, the Company had approximately $17.0 million of contractual obligations related to its non-cancelable leases, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASU 2016-02.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition, and most industry-specific guidance. ASU 2014-09 provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. In addition, new qualitative and quantitative disclosure requirements aim to enable financial statement users to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to fiscal 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 permit retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial application. The Company plans to adopt these ASUs effective January 1, 2018. Although the Company is still 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.

Note 2—Property Acquisitions

2017 Acquisition

On June 8, 2017, the Company completed the GMT Acquisition and acquired interests in 36 producing horizontal wells plus undeveloped acreage on approximately 11,850 net acres (14,770 gross acres) in Lea County, New Mexico for an unadjusted purchase price of $350.0 million. The Company operates approximately 79% of, and has an approximate 85% average working interest, in this acreage. The acquired acres are located in the Northern Delaware Basin with drilling locations in the Avalon Shale, 2nd Bone Spring Sand, 3rd Bone Spring Sand and Wolfcamp A formations.

The GMT Acquisition was recorded as an asset acquisition under ASU 2017-01. Accordingly, the GMT purchase consideration has been allocated to the GMT oil and natural gas properties based on their relative fair values measured as of the acquisition date. After settlement statement adjustments of $0.9 million, the Company paid a net purchase price of $349.1 million. On a relative fair value basis, $296.2 million was allocated to unproved properties and $53.2 million to proved properties. Transaction costs as they relate to the GMT Acquisition mainly consist of advisory, legal and accounting fees and are capitalized as incurred, and the Company has incurred $0.4 million in capitalized transaction costs related to this acquisition as of June 30, 2017.

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2016 Acquisition

In December 2016, the Company acquired interests in 31 producing horizontal wells plus undeveloped acreage on approximately 35,500 net acres (43,500 gross acres) in Reeves County, Texas for an unadjusted purchase price of $855.0 million, which consisted of cash consideration paid by the Company and a $32.3 million payable at December 31, 2016 that was settled in 2017 when title issues relating to the purchased acreage were satisfied. The Company operates approximately 90% of, and has an approximate 90% working interest in this acreage. The Wolfcamp A and Wolfcamp B are producing horizons on this acreage, and the Company believes that this acreage may be prospective for the Wolfcamp C 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 assumed on 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 properties	753,763
Proved properties	116,700
Other property and equipment	56
Liabilities	(2,747		)
Total	$	867,772

The pro forma effects of the Silverback Acquisition were insignificant to the Company’s 2016 results of operations.

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 billings	7,713		2,942
Hedge settlements	292		194
Other	62		2
Accounts receivable, net	$	34,809	$	14,734

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Accounts payable and accrued expenses are comprised of the following:



(in thousands)	June 30, 2017		December 31, 2016
Accounts payable	$	44,478	$	11,210
Accrued capital expenditures	56,228		24,038
Revenues payable	9,922		3,815
Payable to Silverback	—		32,293
Accrued underwriting fees	—		7,719
Other	8,880		7,025
Accounts payable and accrued expenses	$	119,508	$	86,100

Note 4—Long-Term Debt

Credit Agreement

CRP, the Company’s consolidated subsidiary, has a credit agreement with a syndicate of banks that as of June 30, 2017 had a borrowing base of $350.0 million, which has been committed by lenders and is available for borrowing. A portion of the revolving credit facility in an aggregate amount not to exceed $15.0 million may be used to issue letters of credit for the account of CRP or other designated subsidiaries of the Company. As of June 30, 2017, the Company had $314.1 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's revolving credit facility is subject to a borrowing base that is redetermined semi-annually each April 1 and October 1 by the lenders in their sole discretion. CRP's credit agreement also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the volumes of CRP’s proved oil and natural gas reserves and estimated cash flows from these reserves and its commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under its credit agreement. The credit facility provides for interest only payments until October 15, 2019, when the credit agreement expires and all outstanding borrowings are due.

The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-term debt as of June 30, 2017 (in thousands):



	2017	2018	2019	2020	2021
Long-term debt	—	—	35,000	—	—

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. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount and are included in interest expense in the accompanying statements of operations.

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 our 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) a current ratio, which is the ratio of CRP’s consolidated current assets (including unused commitments under its revolving credit facility and excluding non-cash assets under 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 our credit agreement and non-cash liabilities under ASC 815), of not less than 1.0 to 1.0; and (2) 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, 2017 and through the filing of this report.

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Note 5—Asset Retirement Obligations

The following table summarizes the changes in the Company’s asset retirement obligations (“AROs”) for the six months ended June 30, 2017:



(in thousands)	Six Months Ended June 30, 2017
Asset retirement obligations, beginning of period	$	7,226
Additional liabilities incurred	1,443
Liabilities settled	(29		)
Accretion expense	233
Revision to estimated cash flows	(18		)
Asset retirement obligations, end of period	$	8,855

Asset retirement obligations 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 AROs 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 adjustment is made to the oil and natural gas property balance.

Note 6—Equity 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 awards	1,967		3,721
Total equity based compensation expense	$	2,985	$	5,595

Equity 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, the Company had 11,866,072 shares of Class A Common Stock available for future grants. The LTIP provides for grants of stock options, including incentive stock options (“ISOs”) and nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units (“RSUs”) and other stock or cash based awards.

Restricted Stock

The following table provides information about restricted stock awards granted during the six months ended June 30, 2017:



	Awards		Weighted Average Grant-Date Fair Value
Service-based stock awards:
Outstanding as of December 31, 2016	256,597		$	20.03
Vested	—		$	—
Granted	324,010		$	18.77
Canceled	(6,679	)	$	18.81
Outstanding as of June 30, 2017	573,928		$	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

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restricted shares at June 30, 2017 was $8.8 million. The Company expects to recognize that cost over a weighted average period of 2.4 years.

Stock Options

Options that have been granted under the LTIP expire ten years from the grant date and have service-based vesting schedules of three years. The exercise price for an option under the LTIP is the closing price of the Company’s Class A Common Stock as reported by NASDAQ on the date of grant.

Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. The Company estimates the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the re-levered asset volatility implied by a set of comparable companies. Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.

The following table summarizes the assumptions and related information used to determine the grant date fair value of stock options awarded during the six months ended June 30, 2017:



	Six Months Ended June 30, 2017
Weighted average grant-date fair value	$	7.15
Expected term (in years)	6
Expected stock volatility	38.1		%
Dividend yield	—		%
Risk-free interest rate	2.0		%

Information about outstanding stock options is summarized in the table below:



	Options		Weighted Average Exercise Price		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding as of December 31, 2016	2,735,500		$	14.67	5.8	$	13,804
Exercised	—		$	—	—	$	—
Granted	1,547,500		$	17.97	5.6	$	36
Forfeited	(223,000	)	$	14.54	5.3	$	289
Outstanding as of June 30, 2017	4,060,000		$	15.94	5.5	$	3,018
Exercisable as of June 30, 2017	—		$	—	—	$	—

As of June 30, 2017, there was $21.2 million of unrecognized compensation cost related to non-vested stock options. The Company expects to recognize that cost on a pro rata basis over a weighted average period of 2.5 years.

Note 7—Derivative Instruments

The Company is exposed to certain risks relating to its ongoing business operations, and it uses derivative instruments mainly to manage its commodity price risk.

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 costless collars and 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. 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.

The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of June 30, 2017:

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(Unaudited)



	Period	Volume (Bbl)	Weighted Average Fixed Price ($/Bbl)
Crude oil swaps	July 2017 - December 2017	340,400	$	50.41
	January 2018 - December 2018	36,500	$	55.95
Crude oil basis swaps	July 2017 - November 2017	51,742	$	(0.20	)

	Period	Volume (MMBtu)	Weighted Average Fixed Price ($/MMBtu)
Natural gas swaps	July 2017 - December 2017	736,000	$	2.94

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.

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 statements of operations. All derivative instruments are recorded at fair value in the condensed 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		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 gain (loss) on derivative instruments	$	2,529	$	(7,843	)	$	6,288	$	(5,925	)

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 sheets as derivative assets and liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master netting agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The following tables summarize the location and fair value amounts of all the Company’s derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the condensed consolidated balance sheets:



	June 30, 2017
(in thousands)	Balance Sheet Classification	Gross Asset/Liability Amounts		Gross Amounts Offset (1)			Net Recognized Fair Value Assets/Liabilities
Derivative Assets
Derivative instruments	Current assets	$	1,675	$	(159	)	$	1,516
Derivative instruments	Noncurrent assets	131		—			131
Total derivative assets		$	1,806	$	(159	)	$	1,647
Derivative Liabilities
Derivative instruments	Current liabilities	$	344	$	(159	)	$	185
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 instruments	Current assets	$	739	$	(308	)	$	431
Total derivative assets		$	739	$	(308	)	$	431
Derivative Liabilities
Derivative instruments	Current liabilities	$	5,669	$	(308	)	$	5,361
Derivative instruments	Noncurrent 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 Centennial is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

In addition, the Company is exposed to credit risk associated with its derivative contracts from non-performance by its counterparties. The Company mitigates its exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of CRP’s credit facility as referenced above.

Note 8—Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

The following table is a listing of the 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, 2017 and December 31, 2016:



(in thousands)	Level 1		Level 2			Level 3
Commodity derivative asset (liability)
June 30, 2017	$	—	$	1,462		$	—
December 31, 2016	—		(4,950		)	—

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The 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 3 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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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 for additional information on the fair value of assets acquired during 2016 and 2017.

Other Financial Instruments

The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying values of the amounts outstanding under CRP’s credit agreement approximate fair value because the variable interest rates are reflective of current market conditions.

Note 9—Shareholders' Equity and Noncontrolling Interest

Shareholders’ Equity

Class A Common Stock

On May 25, 2017, the Company’s stockholders approved at a special meeting the issuance of 26,100,000 shares of Class A Common Stock upon the conversion of 104,400 shares of Series B Preferred Stock issued and sold to affiliates of Riverstone Investment Group LLC in a private placement. The proceeds of 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

The noncontrolling interest in CRP is represented by 19.2 million shares of Class C Common Stock issued to the Centennial Contributors in connection with the Business Combination and is held by holders other than the Company. As of June 30, 2017, the Company’s noncontrolling interest was 6.9%, which declined from 7.6% as of March 31, 2017, due to the issuance of 23.5 million shares of Class A Common Stock on June 8, 2017. The Company has consolidated the financial position and results of operations of CRP and reflected that portion retained by the other holders as a noncontrolling interest.

The following table summarizes the activity for the equity 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	$	—

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 shareholders by the weighted average shares outstanding during each period. Dilutive net EPS is calculated by dividing adjusted net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted EPS calculation consists of (i) unvested restricted stock awards, outstanding stock options and warrants using the treasury stock method, and (ii) the Company’s Class C common stock using the “if-converted” method.

The Company’s shares of Series B Preferred Stock were converted into shares of Class A Common Stock on May 25, 2017 as a result of shareholder vote. As such, the Company no longer has any participating shares and therefore does not utilize the two-class method. Shares of the Company’s unvested restricted stock 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 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 Stock	1,477		1,995
Adjusted net income attributable to common shareholders	22,239		32,580

Basic net earnings per share	$	0.09	$	0.14
Diluted net earnings per share	$	0.09	$	0.14

Basic weighted average shares outstanding	223,623		212,759
Add: Dilutive effects of equity awards	925		2,046
Add: Dilutive effects of conversion	19,156		19,156
Diluted weighted average shares outstanding	243,704		233,961

Note 12—Transactions with Related Parties

Customer and Supplier Relationships

Riverstone Affiliated Companies. From time to time, the Company obtains services related to its drilling and completion activities from affiliates of Riverstone. In particular, the Company has paid the following amounts to the following affiliates of Riverstone for such services: (i) approximately $27.7 million and $40.2 million during the three and six months ended June 30, 2017 (Successor), respectively, to Liberty Oilfield Services, LLC (“Liberty”); and (ii) approximately $1.3 million and $2.4 million during the three and six months ended June 30, 2017 (Successor), respectively, to Permian Tank and Manufacturing, Inc. (“Permian”). At June 30, 2017, included in Accounts payable and accrued expenses was $10.1 million and $0.4 million due to Liberty and Permian, respectively.

Other Affiliated Companies. Mark G. Papa, our 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), the Company paid approximately $3.2 million and $3.9 million, respectively, to Oil States. At June 30, 2017, included in Accounts payable and accrued expenses was $0.9 million due to Oil States.

NGP Affiliated Companies. Beginning December 28, 2016, NGP and entities affiliated with NGP were no longer considered related parties of the Company and any expenses incurred on or after December 28, 2016 with NGP 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, 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—Commitments and Contingencies

Commitments

In June 2017, the Company entered into a transportation service agreement by which the Company is required to deliver 40,000 MMBtu per day for a term of one year. This delivery commitment is tied to natural gas production in Reeves and Ward Counties, Texas.

Other than the above, there have been no material changes in commitments during the six months ended June 30, 2017. Please refer to Note 13—Commitment and Contingencies included in Part II, Item 8. in our 2016 Annual Report.

Contingencies

In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the 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.

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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, 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 2016 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 are an independent oil and natural gas company focused on the development of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. Our capital programs are specifically focused on projects that we believe provide the greatest potential for repeatable success and production growth. We also selectively pursue acquisitions that complement our existing core properties, such as the Silverback Acquisition and GMT Acquisition.

Market Conditions

The oil and natural gas industry is cyclical and commodity prices can be volatile. In the second half of 2014, oil prices began a rapid and significant decline as global and domestic supply began to outpace demand. During 2015 and through 2016, global and domestic oil supply continued to outpace demand resulting in further deterioration in realized oil prices. Thus far into 2017, oil prices have been volatile, and it is likely that oil prices will continue to fluctuate due to the ongoing global supply and demand imbalance, high inventories and geopolitical factors.

The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2015:



	2015								2016								2017
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2
Crude oil (per Bbl)	$	48.62	$	57.84	$	46.60	$	42.16	$	33.59	$	45.70	$	45.00	$	49.27	$	51.82	$	48.32
Natural gas (per MMBtu)	$	2.81	$	2.74	$	2.73	$	2.24	$	1.98	$	2.25	$	2.80	$	3.17	$	3.06	$	3.14

Although oil and natural gas prices have begun to recover from the lows experienced during the first quarter of 2016, forecast prices for both oil and natural gas have not rebounded to 2014 levels. A sustained drop in oil, natural gas and NGL prices may not only decrease our revenues on a per unit basis but 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 NGL prices may also reduce the borrowing base under CRP’s credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. 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.

2017 Highlights and Future Considerations

Operational Highlights

We operated a five rig program for a majority 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 of approximately 4,840 feet.

Acquisition Highlights

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In June 2017, we completed the acquisition of interests in 36 producing horizontal wells plus undeveloped acreage on approximately 11,850 net acres 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 million.

Financing Highlights

In connection with the GMT Acquisition, in June 2017, we issued and sold in a private placement 23,500,000 shares of our Class A Common Stock to certain other investors, resulting in gross proceeds of approximately $341.0 million, which were used to fund the majority of the acquisition purchase price.

Results of Operations

Three Months Ended June 30, 2017 (Successor) Compared to Three Months Ended June 30, 2016 (Predecessor)

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 June 30, 2017			For the Three Months Ended June 30, 2016		$			%
Net revenues (in thousands):
Oil sales	$	70,735		$	20,361	$	50,374		247	%
Natural gas sales	12,133			1,775		10,358			584	%
NGL sales	8,196			1,211		6,985			577	%
Total net revenues	$	91,064		$	23,347	$	67,717		290	%

Average sales prices:
Oil (per Bbl)	$	44.57		$	41.64	$	2.93		7	%
Effect of derivative settlements on average price (per Bbl)	0.24			12.36		(12.12		)	(98	)%
Oil net of hedging (per Bbl)	$	44.81		$	54.00	$	(9.19	)	(17	)%

Average NYMEX price for oil (per Bbl)	$	48.32		$	45.70	$	2.62		6	%

Natural gas (per Mcf)	$	2.78		$	2.04	$	0.74		36	%
Effect of derivative settlements on average price (per Mcf)	(0.02		)	—		(0.02		)	100	%
Natural gas net of hedging (per Mcf)	$	2.76		$	2.04	$	0.72		35	%

Average NYMEX price for natural gas (per Mcf)	$	3.14		$	2.25	$	0.89		40	%

NGL (per Bbl)	$	21.34		$	15.33	$	6.01		39	%

Net production:
Oil (MBbls)	1,587			489		1,098			225	%
Natural gas (MMcf)	4,372			869		3,503			403	%
NGLs (MBbls)	384			79		305			386	%
Total (MBoe) (1)	2,700			713		1,987			279	%

Average daily net production volume:
Oil (Bbls/d)	17,435			5,374		12,061			224	%
Natural gas (Mcf/d)	48,042			9,549		38,493			403	%
NGLs (Bbls/d)	4,222			868		3,354			386	%
Total (Boe/d) (1)	29,664			7,833		21,831			279	%

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(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 three months ended June 30, 2017 (Successor) were $67.7 million (or 290%) higher than total net revenues for the three months ended June 30, 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 225%, 403% and 386%, 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 170 MBbls of net oil production to our second quarter 2017 results. In addition, we placed 38 operated wells on production in the Delaware Basin since the second quarter of 2016, which added 1,076 MBbls of net oil production to the second quarter 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 second quarter of 2017 (41%) as compared to the second quarter of 2016 (31%).

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 second quarter of 2017 compared to the same 2016 period. Our average price for oil before the effects of hedging increased 7%, our average price for natural gas before the effects of hedging increased 36% and our average price for NGLs increased 39% between periods. Of the 7% increase in our average realized oil price, 6% of such increase was related to higher average NYMEX crude prices between periods, and the remaining 1% was attributable to slightly wider oil differentials in the second quarter of 2017 due to a portion of our oil volumes being trucked while wells awaited connection into nearby pipelines. 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% 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 second quarter 2016 to second quarter 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 Three Months Ended June 30, 2017		For the Three Months Ended June 30, 2016		$			%
Operating expenses (in thousands):
Lease operating expenses	$	8,273	$	2,597	$	5,676		219	%
Severance and ad valorem taxes	4,723		1,247		3,476			279	%
Gathering, processing and transportation expenses	7,403		1,459		5,944			407	%
Production costs per Boe:
Lease operating expenses	$	3.06	$	3.64	$	(0.58	)	(16	)%
Severance and ad valorem taxes	1.75		1.75		—			—	%
Gathering, processing and transportation expenses	2.74		2.05		0.69			34	%

Lease Operating Expenses. Our lease operating expenses (“LOE”) for the three months ended June 30, 2017 (Successor) increased $5.7 million compared to the three months ended June 30, 2016 (Predecessor). Higher LOE for the second quarter of 2017 was primarily related to a $4.6 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 $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 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 second quarter of 2017 to the same 2016 period. LOE per Boe was $3.06 for the second quarter of 2017, which represents a decrease of $0.58 per Boe (or 16%) from the second

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quarter 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 three months ended June 30, 2017 (Successor) increased $3.5 million (or 279%) compared to the three months ended June 30, 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 flat between periods at 5.2% for the three months ended June 30, 2017 compared to 5.3% for the same 2016 period.

Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended June 30, 2017 (Successor) increased $5.9 million compared to the three months ended June 30, 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 $2.05 for the second quarter of 2016 to $2.74 per Boe for the second quarter of 2017. This increase in rate was mainly due to a 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 second quarter 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 volumes (i.e. excluding crude oil barrels) sold, such per BOE rate remained relatively consistent between periods at $6.65 and $6.52 for the second quarters of 2017 and 2016, respectively.

Depreciation, Depletion and Amortization. The following table summarizes our DD&A for the periods indicated:



	Successor		Predecessor
(in thousands)	For the Three Months Ended June 30, 2017		For the Three Months Ended June 30, 2016
Depreciation, depletion and amortization	$	34,300	$	21,182
Depreciation, depletion and amortization per Boe	12.70		29.71

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 three months ended June 30, 2017 (Successor), DD&A expense amounted to $34.3 million, an increase of $13.1 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 $58.9 million of incremental DD&A expense being incurred during the second quarter of 2017. This $58.9 million of incremental DD&A was largely offset by a $45.9 million reduction in DD&A expense during the second quarter of 2017, that was attributable to significantly lower DD&A rates between periods.

On a Boe basis our overall DD&A rate of $12.70 for the second quarter of 2017 was 57% lower than the rate of $29.71 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 Three Months Ended June 30, 2017		For the Three Months Ended June 30, 2016
Equity based compensation expense	$	667	$	—
Geological and geophysical costs	1,803		262
Exploration expense	$	2,470	$	262

Exploration expense increased $2.2 million for the three months ended June 30, 2017 (Successor) compared to the same prior year period (Predecessor). Exploration includes costs of topographical, geographical and geophysical (“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 general and administrative (“G&A”) expenses for the periods indicated:

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	Successor		Predecessor
(in thousands)	For the Three Months Ended June 30, 2017		For the Three Months Ended June 30, 2016
Equity based compensation expense	$	2,318	$	—
Cash general and administrative expenses	8,323		2,607
General and administrative expenses	$	10,641	$	2,607

G&A expenses for the three months ended June 30, 2017 (Successor) increased $8.0 million over the same 2016 period (Predecessor). This increase was primarily due to $4.3 million in higher employee salaries and related costs between periods, $2.3 million of stock-based compensation incurred during the second quarter of 2017 versus none in the same prior year period, and $1.1 million in increased professional fees. Employee-related costs were substantially higher during the second quarter of 2017 due to the number of administrative employees (i.e. non-billable to our joint interest partners) increasing from 28 at June 30, 2016 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.

Other Income and Expenses. The following table summarizes our other income and expenses 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 instruments	2,529			(7,843		)
Other income	$	—		$	6
Total other income (expense)	$	9,013		$	(9,635	)
Income tax (expense) benefit	$	(9,069	)	$	406

Gain on Sale 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 related to the sale of our Pecos County, Texas acreage.

Interest Expense. For the three months ended June 30, 2017 (Successor), we recorded $0.7 million in interest related to CRP’s credit facility. For the three months ended June 30, 2016 (Predecessor), we recorded $0.8 million in 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 outstanding during the second quarter of 2017 was $28.6 million versus $98.7 million for 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.

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 three months ended June 30, 2017 (Successor), we recognized non-cash mark-to-market derivative gains of $2.2 million, and for the three months ended June 30, 2016 (Predecessor), we recognized non-cash mark-to-market 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.

Income Tax Expense. During the three 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 three months ended June 30, 2016 (Predecessor). The Company's provision for income taxes for the three 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 $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:

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	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 sales	20,374			3,088		17,286			560	%
NGL sales	14,371			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

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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 taxes	7,910		2,091		5,819			278	%
Gathering, processing and transportation expenses	12,647		2,589		10,058			388	%
Production costs per Boe:
Lease operating expenses	$	3.57	$	4.85	$	(1.28	)	(26	)%
Severance and ad valorem taxes	1.81		1.53		0.28			18	%
Gathering, processing and transportation expenses	2.90		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

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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 Boe	13.86		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 costs	1,803		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 expenses	17,778		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:

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	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 properties	7,357			(4		)
Interest expense	$	(1,117	)	$	(3,439	)
Net gain (loss) on derivative instruments	6,288			(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 for 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%.

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Liquidity and Capital Resources

Overview

Our development and acquisition activities require us to make significant operating and capital expenditures. Historically, our primary sources of liquidity have been borrowings under CRP’s revolving credit facility, cash flows from operations and proceeds from asset dispositions and, prior to the Business Combination, capital contributions from CRP’s equity sponsors. To date, our primary use of capital has been for the acquisition and development of oil and natural gas properties.

The following table summarizes our capital expenditures incurred for the six months ended June 30, 2017:



(in millions)	Six Months Ended June 30, 2017
Drilling and completion capital expenditures	$	235.1
Land and other	26.3
Facilities, seismic and other	9.0
Total capital expenditures	270.4

We continually evaluate our capital needs and compare them to our capital resources. Our estimated capital expenditure budget for 2017 is $535.0 million to $625.0 million, which we expect to fund with cash flows from operations and borrowings under our credit facility. The drilling and completion (“D&C”) portion of our 2017 capital budget represents a significant increase over the $97.7 million of D&C expenditures incurred during 2016. This increased capital budget is in response to the higher level of anticipated cash flows to be generated from (i) new wells we drilled and completed in latter 2016 and plan to drill in 2017, (ii) wells we added in the Silverback Acquisition and GMT Acquisition and (iii) higher crude oil and natural gas prices experienced during the fourth quarter of 2016 and continuing into 2017, as well as our strong balance sheet position with minimal borrowings outstanding as of June 30, 2017.

Because we are the operator of a high percentage of our acreage, the amount and timing of these capital expenditures are largely discretionary. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners.

Based upon current oil and natural gas price expectations for the remainder of 2017, we believe that our cash flow from operations and borrowings under CRP’s revolving credit facility will provide us with sufficient liquidity to execute our current capital program. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot ensure that operations and other needed capital will be available on acceptable terms or at all. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base borrowings, asset sales, offerings of debt and equity securities 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:

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	Successor			Predecessor
(in thousands)	For the Six Months Ended June 30, 2017			For the Six Months Ended June 30, 2016
Net cash provided by operating activities	$	93,140		$	35,604
Net cash used in investing activities	(595,325		)	(85,455		)
Net cash provided by financing activities	368,102			48,767

During the first half of 2017, we generated $93.1 million of cash provided by operating activities, an increase of $57.5 million from the same period in 2016. Cash provided by operating activities increased primarily due to higher crude oil, natural gas and NGL production volumes; higher realized sales prices for oil, natural gas and NGLs; and lower cash interest during the first half of 2017. 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 during the first half of 2017 as compared to the same period in 2016. 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 half of 2017, cash flows from operating activities and cash on hand were used to finance $198.3 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 million in oil and gas property acquisitions.

Revolving Credit Facility

Our consolidated subsidiary CRP has a credit agreement with a syndicate of banks that as of June 30, 2017 had a borrowing base of $350.0 million, which has been committed by lenders and is available for borrowing. A portion of the revolving credit facility in an aggregate amount not to exceed $15.0 million may be used to issue letters of credit for the account of CRP or other designated subsidiaries of the Company. As of June 30, 2017, the Company had $314.1 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's revolving credit facility is subject to a borrowing base that is redetermined semiannually each April 1 and October 1 by the lenders in their sole discretion. CRP's credit agreement also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the volumes of CRP's proved oil and natural gas reserves and estimated cash flows from these reserves and its commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under its credit agreement. The credit facility provides for interest only payments until October 2019, when the credit agreement expires and all outstanding borrowings are due.

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 of its revolving credit facility of 50 basis points. CRP may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

CRP’s credit agreement also requires it to maintain compliance with the following financial ratios: (1) a current ratio, which is the ratio of CRP’s consolidated current assets (including unused commitments under its revolving credit facility and excluding non-cash assets under 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 our credit agreement and non-cash liabilities under ASC 815), of not less than 1.0 to 1.0; and (2) a leverage ratio, which is the ratio of Total Funded Debt (as defined in CRP’s credit agreement) to consolidated EBITDAX (as defined in

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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, 2017 and through the filing of this report.

Off-Balance Sheet Arrangements

As of June 30, 2017, we had no off-balance sheet arrangements.

Critical Accounting Policies and Estimates

There have been no material changes during the six months ended June 30, 2017 to the methodology applied by management for critical accounting policies previously disclosed in our 2016 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 2016 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 report for new accounting matters.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLs production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future.

Due to this volatility, we have historically used, and we expect to continue to opportunistically use, commodity derivative instruments, such as swaps, collars and basis swaps, to hedge price risk associated with a portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices and may partially limit our potential gains from future increases in prices. CRP’s credit agreement limits its ability to enter into commodity hedges covering greater than 80% of its reasonably anticipated projected production volume.

Our open positions as of June 30, 2017:



Description & Production Period	Volume (Bbl)	Weighted Average Fixed Price ($/Bbl) (1)
Crude Oil Swaps:
July 2017 - December 2017	46,000	$	64.05
July 2017 - December 2017	18,400	54.65
July 2017 - December 2017	18,400	43.50
July 2017 - December 2017	18,400	44.85
July 2017 - December 2017	18,400	45.10
July 2017 - December 2017	55,200	44.80
July 2017 - December 2017	18,400	47.27
July 2017 - December 2017	18,400	49.00
July 2017 - December 2017	92,000	49.80
July 2017 - December 2017	36,800	52.35
January 2018 - December 2018	36,500	55.95
Crude Oil Basis Swaps:
July 2017 - November 2017	36,958	$	(0.20	)
July 2017 - November 2017	14,784	(0.20		)


(1)	The oil swap contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis derivative contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period.


(1)	The natural gas derivative contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas.

The fair value of these commodity derivative instruments at June 30, 2017 was a net asset of $1.5 million. A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of June 30, 2017 would cause a $1.8 million increase or decrease, respectively, in this fair value liability, and a hypothetical upward or downward shift of 10% per Mcf in the NYMEX forward curve for natural gas as of June 30, 2017 would cause a $0.2 million increase or decrease, respectively, in this fair value liability.

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Interest Rate Risk

At June 30, 2017, we had $35.0 million of debt outstanding, with a weighted average interest rate of 3.35%. Interest is calculated under the terms of CRP’s credit agreement based on a LIBOR spread. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the assumed weighted average interest rate would be approximately $0.4 million per year. 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.

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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. 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, 2017 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, 2017 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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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, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our 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 2016 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
2.1		Purchase 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 Amended and Restated Credit Agreement, dated as of April 28, 2017, by and among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders and guarantors party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 1, 2017).
10.2		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).
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.

Table of Contents

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:	August 8, 2017

Description & Production Period

Volume (MMBtu)

Weighted Average Fixed Price ($/MMBtu) (1)

Natural Gas Swaps:

July 2017 - December 2017