Permian Resources - 10-Q quarterly report FY2017 Q3

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 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 October 31, 2017, there were 256,731,091 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		8

Item 1.	Financial Statements (Unaudited)	8

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

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

	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	10

	Condensed Consolidated Statement of Shareholders’ Equity for the Nine Months Ended September 30, 2017	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	38

Item 4.	Controls and Procedures	40

Part II—OTHER INFORMATION		41

Item 1.	Legal Proceedings	41

Item 1A.	Risk Factors	41

Item 6.	Exhibits	41

Signatures		42

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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.

Bbls/d. Barrels per day.

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

Boe/d. One Boe per day.

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

Completion. 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.

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

MBoe. One thousand Boe.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One Mcf per day.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

NGL. Natural gas liquids. 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.

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.

IPO. Our initial public offering of units, which closed on February 29, 2016.

NewCo. New Centennial, LLC, a Delaware limited liability company controlled by affiliates of Riverstone.

NGP Follow-On. NGP Centennial Follow-On LLC, a Delaware limited liability company.

Private Placement Warrants. Our 8,000,000 outstanding warrants for the purchase of shares of Class A Common Stock, which were purchased by our Sponsor in a private placement simultaneously with the closing of our IPO.

Public Warrants. Warrants for the purchase of shares of Class A Common Stock sold as part of the Units in our IPO, all of which have been exercised or redeemed and are no longer outstanding.

Riverstone. Riverstone Investment Group LLC and its affiliates, including 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 (“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 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)



	September 30, 2017			December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	2,581		$	134,083
Accounts receivable, net	50,207			14,734
Derivative instruments	383			431
Prepaid and other current assets	6,104			2,078
Total current assets	59,275			151,326
Oil and natural gas properties, successful efforts method
Unproved properties	2,008,902			1,905,661
Proved properties	1,306,873			605,853
Accumulated depreciation, depletion and amortization	(115,343		)	(14,436)
Total oil and natural gas properties, net	3,200,432			2,497,078
Other property and equipment, net	3,897			2,193
Total property and equipment, net	3,204,329			2,499,271
Noncurrent assets
Derivative instruments	242			—
Other noncurrent assets	10,766			1,045
Total assets	$	3,274,612		$	2,651,642
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses	$	136,495		$	86,100
Derivative instruments	450			5,361
Total current liabilities	136,945			91,461
Noncurrent liabilities
Revolving credit facility	165,000			—
Asset retirement obligations	9,328			7,226
Deferred tax liability	17,302			—
Derivative instruments	—			20
Total liabilities	328,575			98,707
Shareholders’ equity
Preferred stock, $0.0001 par value, 1,000,000 shares authorized:
Series A: 1 share issued and outstanding	—			—
Series B: no shares issued and outstanding at September 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: 257,760,091 shares issued and 256,670,839 shares outstanding at September 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	2,704,298			2,364,049
Retained earnings (accumulated deficit)	36,103			(8,929		)
Total shareholders’ equity	2,740,429			2,355,142
Noncontrolling interest	205,608			197,793
Total equity	2,946,037			2,552,935
Total liabilities and shareholders’ equity	$	3,274,612		$	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 September 30, 2017			For the Three Months Ended September 30, 2016			For the Nine Months Ended September 30, 2017			For the Nine Months Ended September 30, 2016
Net revenues
Oil sales	$	87,286		$	23,388		$	204,702		$	56,975
Natural gas sales	12,852			2,629			33,226			5,717
NGL sales	11,473			1,304			25,844			3,097
Total net revenues	111,611			27,321			263,772			65,789
Operating expenses
Lease operating expenses	11,373			3,656			26,924			10,295
Severance and ad valorem taxes	6,448			1,432			14,358			3,523
Gathering, processing and transportation expenses	9,925			1,787			22,572			4,375
Depreciation, depletion and amortization	42,387			18,454			102,847			60,939
Impairment and abandonment expenses	—			1,649			(29		)	2,546
Exploration expense	1,622			402			4,092			920
General and administrative expenses	13,311			4,848			36,017			9,735
Total operating expenses	85,066			32,228			206,781			92,333
Total operating income (loss)	26,545			(4,907		)	56,991			(26,544		)
Other income (expense)
Gain (loss) on sale of oil and natural gas properties	(141		)	15			7,216			11
Interest expense	(1,015		)	(1,983		)	(2,132		)	(5,422		)
Net gain (loss) on derivative instruments	(896		)	1,741			5,392			(4,184		)
Other income	—			—			—			6
Other income (expense)	(2,052		)	(227		)	10,476			(9,589		)
Income (loss) before income taxes	24,493			(5,134		)	67,467			(36,133		)
Income tax (expense) benefit	(8,233		)	—			(17,302		)	406
Net income (loss)	16,260			(5,134		)	$	50,165		$	(35,727	)
Less: Net income attributable to noncontrolling interest	1,813			—			5,133			—
Net income (loss) attributable to common shareholders	$	14,447		$	(5,134	)	$	45,032		$	(35,727	)
Income per share:
Basic	$	0.06					$	0.20
Diluted	$	0.06					$	0.19

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 Nine Months Ended September 30, 2017			For the Nine Months Ended September 30, 2016
Cash flows from operating activities:
Net income (loss)	$	50,165		$	(35,727	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	102,847			60,939
Stock-based compensation expense	9,420			—
Impairment and abandonment expenses	(29		)	2,546
Deferred tax expense (benefit)	17,302			(406		)
(Gain) loss on sale of oil and natural gas properties	(7,216		)	(11		)
Non-cash portion of derivative (gain) loss	(5,126		)	20,807
Amortization of debt issuance costs	348			363
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(28,172		)	3,021
Increase in prepaid and other assets	(12,890		)	(165		)
Increase in accounts payable and other liabilities	10,501			144
Net cash provided by operating activities	137,150			51,511
Cash flows from investing activities:
Acquisition of oil and natural gas properties	(419,471		)	(55,566		)
Drilling and development capital expenditures	(354,515		)	(45,203		)
Purchases of other property and equipment	(3,482		)	(206		)
Proceeds from sales of oil and natural gas properties	10,714			—
Net cash used in investing activities	(766,754		)	(100,975		)
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	190,000			55,000
Repayment of revolving credit facility	(25,000		)	(5,000		)
Financing obligation	—			(1,894		)
Debt issuance costs	(415		)	—
Net cash provided by financing activities	498,102			48,106
Net decrease in cash and cash equivalents	(131,502		)	(1,358		)
Cash and cash equivalents, beginning of period	134,083			1,768
Cash and cash equivalents, end of period	$	2,581		$	410
Supplemental cash flow information
Cash paid for interest	$	1,915		$	4,993
Supplemental non-cash activity
Accrued capital expenditures included in accounts payable and accrued expenses	$	102,152		$	16,339
Asset retirement obligations incurred, including changes in estimate	$	1,016		$	206

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			Retained Earnings (Accumulated Deficit)			Total Shareholders’ Equity			Noncontrolling Interest		Total Equity
	Shares		Amount		Shares	Amount		Shares	Amount		Shares		Amount		Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			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	841		—		—	—		—	—		—		—		—			—			—			—		—
Restricted stock forfeited	(9	)	—		—	—		—	—		—		—		—			—			—			—		—
Conversion of Series B preferred shares to Class A common shares	26,100		3		—	—		—	—		(104	)	—		(3		)	—			—			—		—
Sale of unregistered Class A common shares	23,500		2		—	—		—	—		—		—		340,748						340,750			—		340,750
Underwriters' discount and offering expense	—		—		—	—		—	—		—		—		(7,233		)	—			(7,233		)	—		(7,233		)
Stock-based compensation	—		—		—	—		—	—		—		—		9,420			—			9,420					9,420
Change in equity due to issuance of shares by Centennial Resource Production, LLC	—		—		—	—		—	—		—		—		(2,682		)	—			(2,682		)	2,682		—
Net income	—		—		—	—		—	—		—		—		—			45,032			45,032			5,133		50,165
Balance at September 30, 2017	257,760		$	26	19,156	$	2	—	$	—	—		$	—	$	2,704,298		$	36,103		$	2,740,429		$	205,608	$	2,946,037

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 located primarily in the Permian Basin of West Texas. Until the closing of the Business Combination, CRP operated as a privately-held independent oil and natural gas company.

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 normal, recurring adjustments and accruals considered necessary for a fair presentation of interim financial information, in all material respects, 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 CRP’s 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.

Principles of Consolidation

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 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.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The more significant areas requiring the use of assumptions, judgments and estimates include: (i) oil and natural gas reserves; (ii) cash flow estimates used in impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset retirement obligations; (v) determining fair value and allocating purchase price in connection with business combinations and asset acquisitions; (vi) valuation of derivative instruments; (vii) accrued revenue and related receivables; and (viii) accrued liabilities.

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 statements of cash flows and will not have a material impact on its consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation. This update applies to all entities that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. The Company elected to early adopt this guidance in October 2016 in conjunction with the issuance of its equity awards.

In February 2016, the FASB issued ASU 2016-02, Leases. 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. The FASB subsequently issued various ASUs which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU 2014-09 and its amendments provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. In addition, new qualitative and quantitative disclosure requirements aim to enable financial statement users to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 and its amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standards permit

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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 does not expect net income or cash flows to be materially impacted by the new standard, however, the Company is currently analyzing whether changes to total revenues and total expenses will be necessary to properly reflect revenue for certain pipeline gathering, transportation and gas processing agreements. The Company continues to evaluate the expected disclosure requirements, changes to relevant business practices, accounting policies and control activities as a result of the adoption of the ASU and has not yet developed estimates of the quantitative impact to the Company's consolidated financial statements. The Company has selected the modified retrospective method and will adopt this guidance on the effective date of January 1, 2018.

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 with the remaining purchase price allocated amongst other assets and liabilities. Transaction costs as they relate to the GMT Acquisition mainly consist of advisory, legal and accounting fees and are capitalized as incurred, and the Company has incurred $0.5 million in transaction costs related to this acquisition as of September 30, 2017.

2016 Acquisition

On December 28, 2016, the Company acquired interests in 31 producing horizontal wells plus undeveloped acreage on approximately 35,500 net acres (43,500 gross acres) 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, 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 September 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

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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)	September 30, 2017		December 31, 2016
Accrued oil and gas sales receivable	$	32,294	$	11,596
Joint interest billings	16,989		2,942
Hedge settlements	126		194
Other	798		2
Accounts receivable, net	$	50,207	$	14,734

Accounts payable and accrued expenses are comprised of the following:



(in thousands)	September 30, 2017		December 31, 2016
Accounts payable	$	35,132	$	11,210
Accrued capital expenditures	71,808		24,038
Revenues payable	16,534		3,815
Payable to Silverback	—		32,293
Accrued underwriting fees	—		7,719
Other	13,021		7,025
Accounts payable and accrued expenses	$	136,495	$	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 September 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 September 30, 2017, the Company had $184.1 million in available borrowing capacity, which was net of $165.0 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, estimated cash flows from these reserves and its commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of permitted issued senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under the credit agreement. In connection with the October 2017 semi-annual redetermination, on November 2, 2017, the Company entered into the fifth amendment to the restated credit agreement to increase the borrowing base from $350.0 million to $575.0 million.

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 consolidated statements of operations. The credit facility provides for interest only payments until October 15, 2019, when the credit agreement expires and all outstanding borrowings are due. The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-term debt as of September 30, 2017 (in thousands):



	2017	2018	2019	2020	2021
Long-term debt	—	—	165,000	—	—

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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: (i) a current ratio, which is the ratio of CRP’s consolidated current assets (including unused commitments under its revolving credit facility and excluding non-cash assets under FASB’s ASC Topic 815, Derivatives and Hedging (“ASC 815”), and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under 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 September 30, 2017 and through the filing of this report.

Note 5—Asset Retirement Obligations

The following table summarizes the changes in the Company’s asset retirement obligations (“ARO”) for the nine months ended September 30, 2017 (in thousands):



Asset retirement obligations at January 1, 2017	$	7,226
Additional liabilities incurred	1,813
Liabilities settled	(65		)
Accretion expense	376
Revision to estimated cash flows	(22		)
Asset retirement obligations at September 30, 2017	$	9,328

ARO reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates and timing of settlement. To the extent future revisions to these assumptions impact the value of the existing ARO liability, a corresponding offsetting adjustment is made to the oil and natural gas property balance.

Note 6—Stock-Based Compensation

Long Term Incentive Plan

On October 7, 2016, the stockholders of the Company approved the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the “LTIP”). An aggregate of 16,500,000 shares of Class A Common Stock were authorized for issuance under the LTIP, and as of September 30, 2017, the Company had 11,199,857 shares of Class A Common Stock available for future grants. The LTIP provides for grants of stock options (including incentive stock options and nonqualified stock options), stock appreciation rights, restricted stock, dividend equivalents, restricted stock units and other stock or cash based awards.

Stock-based compensation expense is recognized within General and administrative expenses and Exploration expense on the consolidated statements of operations as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts. Upon adoption of ASU 2016-09 in October 2016, the Company elected to account for forfeitures of awards granted under these plans as they occur in determining compensation expense.



(in thousands)	For the Three Months Ended September 30, 2017		For the Nine Months Ended September 30, 2017
Restricted stock awards	$	1,490	$	3,364
Stock option awards	2,104		5,825
Performance stock units	231		231
Total stock-based compensation expense	$	3,825	$	9,420

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Restricted Stock

The following table provides information about restricted stock awards outstanding during the nine months ended September 30, 2017:



	Awards		Weighted Average Grant-Date Fair Value
Outstanding as of December 31, 2016	256,597		$	20.03
Vested	—		$	—
Granted	841,443		$	17.21
Forfeited	(8,788	)	$	18.81
Outstanding as of September 30, 2017	1,089,252		$	17.86

The Company grants service-based restricted stock awards to executive officers and employees, which generally vest ratably over a three-year service period, and to directors, which generally vest over a one-year service period. Compensation cost for the service-based restricted stock awards is based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period. Unrecognized compensation cost related to unvested restricted shares at September 30, 2017 was $15.7 million, which the Company expects to recognize over a weighted average period of 2.5 years.

Stock Options

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

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

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



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

The following table provides information about stock option awards outstanding during the nine months ended September 30, 2017:



	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
Exercised	—		$	—
Granted	1,550,000		$	17.96
Forfeited	(268,000	)	$	14.53
Outstanding as of September 30, 2017	4,017,500		$	15.95	9.2	$	8,450
Exercisable as of September 30, 2017	—		$	—	—	$	—

As of September 30, 2017, there was $18.9 million of unrecognized compensation cost related to unvested stock options, which the Company expects to recognize on a pro rata basis over a weighted average period of 2.2 years.

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Performance Stock Units

The Company grants to executive officers performance stock units that are subject to market-based vesting criteria as well as a three-year service period. Vesting at the end of the three-year service period is subject to the condition that our stock price increases by a greater percentage, or decreases by a lesser percentage, than the average percentage increase or decrease, respectively, of the stock prices of a peer group of companies. The market-based conditions must be met in order for the stock awards to vest, and it is, therefore, possible that no shares could vest. However, the Company recognizes compensation expense for the performance stock units subject to market conditions regardless of whether it becomes probable that these conditions will be achieved or not and compensation expense is not reversed if vesting does not actually occur.

The grant-date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of our common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the nine months ended September 30, 2017:



	Nine Months Ended September 30, 2017
Number of simulations	1,000,000
Expected stock volatility	41.6	%
Dividend yield	—	%
Risk-free interest rate	1.5	%

The following table provides information about performance stock units outstanding during the nine months ended September 30, 2017:



	Awards	Weighted Average Grant-Date Fair Value
Outstanding as of December 31, 2016	—	$	—
Vested	—	$	—
Granted	193,391	$	21.53
Forfeited	—	$	—
Outstanding as of September 30, 2017	193,391	$	21.53

As of September 30, 2017, there was $3.9 million of unrecognized compensation cost related to unvested performance stock units, which the Company expects to recognize on a pro rata basis over a weighted average period of 2.75 years.

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Note 7—Derivative Instruments

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

Commodity Derivative Contracts

Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. The Company periodically uses derivative instruments, such as swaps, costless collars and basis swaps, to mitigate its exposure to declines in commodity prices and to the corresponding negative impacts such declines can have on its cash flow from operations, returns on capital and other financial results. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. The Company does not enter into derivative contracts for speculative or trading purposes.

Commodity Swap Contracts. The Company opportunistically uses commodity derivative instruments known as fixed price swaps to realize a known price for a specific volume of production. All transactions are settled in cash with one party paying the other for the net difference in the agreed upon published third-party index price (“index price”) and the swap fixed price, multiplied by the contract volume. The Company also utilizes basis swaps contracts to hedge the difference between the index price and a local index price.

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



	Period	Volume (Bbl)	Weighted Average Fixed Price/Differential ($/Bbl) ⁽¹⁾
Crude oil swaps	October 2017 - December 2017	170,200	$	50.41
	January 2018 - December 2018	36,500	$	55.95
Crude oil basis swaps	October 2017 - November 2017	21,350	$	(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 swap contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period.



	Period	Volume (MMBtu)	Weighted Average Fixed Price/Differential ($/MMBtu) ⁽¹⁾
Natural gas swaps	October 2017 - December 2017	368,000	$	2.94
Natural gas basis swaps	January 2018 - December 2018	1,825,000	$	(0.43	)
	January 2019 - December 2019	1,825,000	$	(0.43	)


⁽¹⁾	The natural gas swap contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas. The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and the NYMEX price of Natural Gas during the relevant calculation period.

Derivative Instrument Reporting. The Company’s oil and natural gas derivative instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in the Company’s condensed consolidated 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.

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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 September 30, 2017			For the Three Months Ended September 30, 2016		For the Nine Months Ended September 30, 2017		For the Nine Months Ended September 30, 2016
Net gain (loss) on derivative instruments	$	(896	)	$	1,741	$	5,392	$	(4,184	)

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:



	September 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	$	562	$	(179	)	$	383
Derivative instruments	Noncurrent assets	246		(4		)	242
Total derivative assets		$	808	$	(183	)	$	625
Derivative Liabilities
Derivative instruments	Current liabilities	$	629	$	(179	)	$	450
Derivative instruments	Noncurrent Liabilities	$	4	$	(4	)	$	—
Total derivative liabilities		$	633	$	(183	)	$	450


⁽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.



	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

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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

Recurring Fair Value Measurements

The Company follows FASB ASC Topic 820, Fair Value Measurement and Disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:


•	Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.


•	Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.


•	Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The following table is a listing of the Company’s netted asset or liability positions that have been measured at fair value and where they have been classified within the fair value hierarchy as of September 30, 2017 and December 31, 2016:



(in thousands)	Level 1		Level 2			Level 3
Commodity derivative asset (liability)
September 30, 2017	$	—	$	175		$	—
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 Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgement and considers factors specific to the asset or liability. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. There were no transfers between any of the fair value levels during any period presented.

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil and natural gas commodity derivatives. The Company uses industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.

Nonrecurring Fair Value Measurements

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and 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.

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the

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calculation of ARO include plugging costs and reserve lives. Refer to Note 5—Asset Retirement Obligations for additional information on the Company’s ARO.

Other Financial Instruments

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

Note 9—Shareholders' Equity and Noncontrolling Interest

Shareholders’ Equity

Class A Common Stock

On May 25, 2017, the Company’s stockholders approved the issuance of 26,100,000 shares of Class A Common Stock upon the conversion of 104,400 shares of Series B Preferred Stock that were held by affiliates of Riverstone, and there was no cash proceeds received by the Company in connection with this issuance. The 104,400 shares of Series B Preferred Stock were originally sold to affiliates of Riverstone in a private placement, whereby the proceeds from such 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

The Company’s Public Warrants were originally issued in connection with the IPO of Silver Run Acquisition Corporation. On March 1, 2017, the Company delivered a notice of redemption to all holders of its Public Warrants announcing its intention to redeem any Public Warrants that remained unexercised and outstanding after March 31, 2017 for $0.01 per Public Warrant. As of September 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 September 30, 2017, 8,000,000 Private Placement Warrants remained outstanding. Private Placement Warrants are non-redeemable so long as they are held by the Company’s Sponsor or its permitted transferees. Each whole Private Placement Warrant is exercisable for one whole share of Class A Common Stock at a price of $11.50 per share. The warrants became exercisable on March 1, 2017 and will expire five years after the completion of the Business Combination or earlier upon redemption or liquidation.

Noncontrolling Interest

The noncontrolling interest in CRP is represented by 19.2 million shares of Class C Common Stock that were issued to the Centennial Contributors in connection with the Business Combination, and such shares continue to be held by holders other than the Company. As of September 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. Refer to the consolidated statement of shareholders’ equity for a summary of the activity attributable to the noncontrolling interest during the period.

Note 10—Income Taxes

CRP is treated as a partnership for U.S. federal and most applicable state and local income tax purposes, and the Company 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.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to the Company’s year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provision for income taxes for the three and nine months ended September 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.

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

Shares of the Company’s unvested restricted stock and performance stock units are eligible to receive dividends; however, dividend rights will be forfeited if the award does not vest. Accordingly, these shares are not considered participating securities. Shares of the Company’s Class C Common Stock and warrants do not share in earnings or losses and are therefore not participating securities as well. In addition, the Company’s shares of Series B Preferred Stock were converted into shares of Class A Common Stock on May 25, 2017 as a result of shareholder vote. As such, the Company no longer has any participating securities and therefore does not utilize the two-class method.

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:



(in thousands, except per share data)	For the Three Months Ended September 30, 2017		For the Nine Months Ended September 30, 2017
Net income attributable to common shareholders	$	14,447	$	45,032
Add: Income from conversion of Class C Common Stock	1,193		3,196
Adjusted net income attributable to common shareholders	15,640		48,228

Basic net earnings per share	$	0.06	$	0.20
Diluted net earnings per share	$	0.06	$	0.19

Basic weighted average shares outstanding	223,622		227,557
Add: Dilutive effects of equity awards	2,598		4,481
Add: Dilutive effects of conversion	19,156		19,156
Diluted weighted average shares outstanding	245,376		251,194

For the three months ended September 30, 2017, the diluted earnings per share calculation excludes 1.5 million stock options that were out-of-the-money, as there effect was anti-dilutive, and for the nine months ended September 30, 2017, the diluted earnings per share calculation excludes 1.0 million stock options that were out-of-the-money, as there effect was anti-dilutive.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 12—Transactions with Related Parties

Customer and Supplier Relationships

Riverstone Affiliated Companies. Riverstone and its affiliates, including our Sponsor, beneficially own more than 10% of our equity interest and are therefore considered related parties. From time to time, the Company obtains services related to its drilling and completion activities from affiliates of Riverstone. In particular, the Company has paid the following amounts to the following affiliates of Riverstone for such services: (i) approximately $30.4 million and $70.6 million during the three and nine months ended September 30, 2017, respectively, to Liberty Oilfield Services, LLC; and (ii) approximately $1.7 million and $4.0 million during the three and nine months ended September 30, 2017, respectively, to Permian Tank and Manufacturing, Inc.

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 nine months ended September 30, 2017, the Company paid approximately $2.4 million and $6.4 million, respectively, to Oil States. At September 30, 2017, included in Accounts payable and accrued expenses on the consolidated balance sheets was $1.5 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 or its affiliates are no longer classified as related party expenses. However, expenses incurred before December 28, 2016 with NGP or its affiliates were classified as related party expenses as NGP beneficially owned more than 10% of our equity interest. Such transactions are detailed below.

In May 2016, the Company acquired undeveloped acreage in Reeves County, Texas and an interest in an uncompleted horizontal wellbore for approximately $9.8 million from Caird DB, LLC, an affiliate of NGP. In addition, the Company paid approximately $3.3 million during the nine months ended September 30, 2016 (Predecessor), 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.

Note 13—Commitments and Contingencies

Commitments

In June 2017, the Company entered into a transportation service agreement whereby it is required to deliver 40,000 MMBtu per day for a term of one year, and this delivery commitment is tied to the Company’s natural gas production in Reeves and Ward counties, Texas.

The Company routinely enters or extends operating agreements, office and equipment leases, drilling and completion rig contracts, among others, in the ordinary course of business. Other than the above, there have been no material, non-routine changes in commitments during the nine months ended September 30, 2017. Please refer to Note 13—Commitment and Contingencies included in Part II, Item 8. in our 2016 Annual Report.

Contingencies

The Company may at times be subject to various commercial or regulatory claims, litigation or other legal proceedings that arise in the ordinary course of business. While the outcome of these lawsuits and claims cannot be predicted with certainty, management believes it is remote that the impact of such matters that are reasonably possible to occur will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Management is unaware of any pending litigation brought against the Company requiring the reserve of a contingent liability as of the date of these condensed consolidated financial statements.

Note 14—Subsequent Events

Credit Facility Amendment

In connection with the October 2017 semi-annual redetermination, on November 2, 2017, the Company entered into the fifth amendment to the restated credit agreement to increase the borrowing base from $350.0 million to $575.0 million.

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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, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed above in “Cautionary Statement Regarding Forward-Looking Statements” and in our 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.

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, commodity prices have been volatile, and it is likely that commodity prices will continue to fluctuate due to global supply and demand, inventory supply levels, weather conditions, geopolitical and other factors.

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



	2015								2016								2017
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3
Crude oil (per Bbl)	$	48.62	$	57.84	$	46.60	$	42.16	$	33.59	$	45.70	$	45.00	$	49.27	$	51.82	$	48.32	$	48.17
Natural gas (per MMBtu)	$	2.81	$	2.74	$	2.73	$	2.24	$	1.98	$	2.25	$	2.80	$	3.17	$	3.06	$	3.14	$	2.95

Although oil and natural gas prices have begun to recover from the lows experienced during the first quarter of 2016, forecast prices for both oil and natural gas have not rebounded to 2014 levels. A sustained drop in oil, natural gas and NGL prices may not only decrease our revenues on a per unit basis but may also reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore potentially lower our oil, natural gas and NGL reserve quantities.

Lower commodity prices in the future could result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity or ability to finance planned capital expenditures. Lower commodity prices may also reduce the borrowing base under CRP’s credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under the credit agreement. 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 six rig program, which allowed us to spud 22 operated wells and complete 13 operated wells during the third quarter. Over half of the completed wells were put on production during September, and the total completed wells during the quarter had an average effective lateral length of approximately 5,800 feet.

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Acquisition Highlights

On June 8, 2017, we completed the GMT Acquisition, which consisted of interests in 36 producing horizontal wells plus approximately 11,850 undeveloped net acres in the core of the Northern Delaware Basin in Lea County, New Mexico for an unadjusted purchase price of $350.0 million.

Financing Highlights

In connection with the GMT Acquisition, in June 2017, we issued and sold in a private placement 23,500,000 shares of our Class A Common Stock to certain institutional investors, which resulted in gross proceeds of approximately $340.8 million, and such proceeds were used to fund the majority of the acquisition purchase price.

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Results of Operations

On October 11, 2016, we consummated the acquisition of approximately 89% of the outstanding membership interests in CRP (the “Business Combination”). Our financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. We are the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination. Except as the context otherwise requires, references in the following discussion to the "Company," "we," "our" or "us" with respect to periods prior to the closing of the Business Combination are to CRP and its operations before the Business Combination.

Three Months Ended September 30, 2017 (Successor) Compared to Three Months Ended September 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 September 30, 2017		For the Three Months Ended September 30, 2016		$			%
Net revenues (in thousands):
Oil sales	$	87,286	$	23,388	$	63,898		273	%
Natural gas sales	12,852		2,629		10,223			389	%
NGL sales	11,473		1,304		10,169			780	%
Total net revenues	$	111,611	$	27,321	$	84,290		309	%

Average sales prices:
Oil (per Bbl)	$	44.95	$	41.69	$	3.26		8	%
Effect of derivative settlements on average price (per Bbl)	0.21		12.36		(12.15		)	(98	)%
Oil net of hedging (per Bbl)	$	45.16	$	54.05	$	(8.89	)	(16	)%

Average NYMEX price for oil (per Bbl)	$	48.17	$	45.00	$	3.17		7	%

Natural gas (per Mcf)	$	2.72	$	2.67	$	0.05		2	%
Effect of derivative settlements on average price (per Mcf)	—		—		—			—	%
Natural gas net of hedging (per Mcf)	$	2.72	$	2.67	$	0.05		2	%

Average NYMEX price for natural gas (per Mcf)	$	2.95	$	2.80	$	0.15		5	%

NGL (per Bbl)	$	24.83	$	14.02	$	10.81		77	%

Net production:
Oil (MBbls)	1,942		561		1,381			246	%
Natural gas (MMcf)	4,733		984		3,749			381	%
NGL (MBbls)	462		93		369			397	%
Total (MBoe) ⁽¹⁾	3,192		818		2,374			290	%

Average daily net production volume:
Oil (Bbls/d)	21,108		6,098		15,010			246	%
Natural gas (Mcf/d)	51,444		10,695		40,749			381	%
NGL (Bbls/d)	5,018		1,011		4,007			396	%
Total (Boe/d) ⁽¹⁾	34,700		8,891		25,809			290	%


⁽¹⁾	Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

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Oil, Natural Gas and NGL Sales Revenues. Our total net revenues for the three months ended September 30, 2017 (Successor) were $84.3 million (or 309%) higher than total net revenues for the three months ended September 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 246%, 381% and 397%, respectively, between periods. The oil volume increase between periods resulted primarily from our drilling success in the Delaware Basin, as well as the producing properties we acquired in the Silverback and GMT Acquisitions, which collectively added 232 MBbls of net oil production to our third quarter 2017 results. Since the third quarter of 2016, we placed 49 operated wells on production in the Delaware Basin, which added 1,416 MBbls of net oil production to the third quarter of 2017. The increase in our operated well count is attributable to the ramp up of our drilling program starting in the fourth quarter of 2016. These oil volume increases were partially offset by normal production declines across 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. Natural gas and NGL volumes were also impacted by the acreage we acquired from Silverback, which has a higher gas/oil ratio. During the third quarter of 2017, our production was made up of 39% natural gas and NGL volumes as compared to 31% in the third quarter of 2016.

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 third quarter of 2017 compared to the same 2016 period. Our average price for oil before the effects of hedging increased 8%, our average price for natural gas before the effects of hedging increased 2% and our average price for NGLs increased 77% between periods. Of the 8% increase in our average realized oil price, 7% of such increase was related to higher average NYMEX crude prices between periods, and the remaining 1% was attributable to slightly narrower oil differentials in the third quarter of 2017. The 2% increase in our average realized natural gas price was similarly related to higher NYMEX prices between periods (average NYMEX gas prices being 5% higher between periods) which effect was partially offset by slightly wider gas differentials experienced in the third quarter of 2017. Of the overall 77% 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 third quarter 2016 to the third 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 September 30, 2017		For the Three Months Ended September 30, 2016		$			%
Operating expenses (in thousands):
Lease operating expenses	$	11,373	$	3,656	$	7,717		211	%
Severance and ad valorem taxes	6,448		1,432		5,016			350	%
Gathering, processing and transportation expenses	9,925		1,787		8,138			455	%
Production costs per Boe:
Lease operating expenses	$	3.56	$	4.47	$	(0.91	)	(20	)%
Severance and ad valorem taxes	2.02		1.75		0.27			15	%
Gathering, processing and transportation expenses	3.11		2.18		0.93			43	%

Lease Operating Expenses. Our lease operating expenses (“LOE”) for the three months ended September 30, 2017 (Successor) increased $7.7 million compared to the three months ended September 30, 2016 (Predecessor). Higher LOE for the third quarter of 2017 was primarily related to a $6.0 million increase associated with a higher well count. We added 49 gross wells through successful drilling and 57 gross wells from the Silverback and GMT Acquisitions. In addition, workover activity increased $1.7 million between periods as a result of our higher well count. We had 65 gross operated horizontal wells as of September 30, 2016 as compared to 171 gross operated horizontal wells as of September 30, 2017.

Our LOE on a per Boe basis, on the other hand, decreased when comparing the third quarter of 2017 to the same 2016 period. LOE per Boe was $3.56 for the third quarter of 2017, which represents a decrease of $0.91 per Boe (or 20%) from the third 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 September 30, 2017 (Successor)

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increased $5.0 million (or 350%) compared to the three months ended September 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 was 5.8% for the three months ended September 30, 2017 compared to 5.2% for the same 2016 period. The increase in rate for the three months ended September 30, 2017, however, is attributable to additional reserves and production in Texas resulting in higher ad valorem assessments, as well as the New Mexico properties we added via the GMT Acquisition which carry a higher severance tax rate of 8.8%.

Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended September 30, 2017 (Successor) increased $8.1 million compared to the three months ended September 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 increased 43% from $2.18 for the third quarter of 2016 to $3.11 per Boe for the third 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 third quarter of 2017, and thus a higher proportion of our production during this 2017 period was subject to gas gathering and transportation charges as well as gas processing fees. On a natural gas and NGL volumes basis (i.e. excluding crude oil barrels) the Boe rate increased only 14% between periods to $7.93 from $6.95 for the third quarters of 2017 and 2016, respectively. This increase was primarily the result of a new firm transportation agreement we entered into in June 2017, which provides guaranteed pipeline capacity for the Company’s natural gas sales (refer to Note 13—Commitments and Contingencies for additional information on such agreement).

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



	Successor		Predecessor
(in thousands)	For the Three Months Ended September 30, 2017		For the Three Months Ended September 30, 2016
Depreciation, depletion and amortization	$	42,387	$	18,454
Depreciation, depletion and amortization per Boe	13.28		22.56

Our DD&A rate can fluctuate as a result of finding and development costs, acquisitions, impairments, as well as changes in proved reserves or proved developed reserves. For the three months ended September 30, 2017 (Successor), DD&A expense amounted to $42.4 million, an increase of $23.9 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 resulted in $53.5 million of incremental DD&A expense being incurred during the third quarter of 2017. This increase was largely offset, however, by a $29.6 million reduction in DD&A expense that was attributable to significantly lower DD&A rates between periods.

On a Boe basis our overall DD&A rate of $13.28 for the third quarter of 2017 was 41% lower than the rate of $22.56 for the same period in 2016. The primary factor contributing to this lower DD&A rate was substantial additions to our proved reserves and proved developed reserves over the past 12 months, coupled with reasonable drilling and completion costs 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 September 30, 2017		For the Three Months Ended September 30, 2016
Stock-based compensation expense	$	465	$	—
Geological and geophysical costs	1,157		402
Exploration expense	$	1,622	$	402

Exploration expense increased $1.2 million for the three months ended September 30, 2017 (Successor) compared to the same prior year period (Predecessor). Exploration expense mainly consists of topographical studies, geographical and geophysical (“G&G”) projects, and salaries and expenses of G&G personnel and consultants. The period over period increase in exploration expense is due to (i) seven geologist positions added since the third quarter of 2016, and (ii) equity-based compensation awards that were granted to G&G personnel in 2017 and during the 2016 Successor period that were not likewise granted as of September 30, 2016.

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General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:



	Successor		Predecessor
(in thousands)	For the Three Months Ended September 30, 2017		For the Three Months Ended September 30, 2016
Stock-based compensation expense	$	3,360	$	—
Cash general and administrative expenses	9,951		4,848
General and administrative expenses	$	13,311	$	4,848

G&A expenses for the three months ended September 30, 2017 (Successor) increased $8.5 million over the same 2016 period (Predecessor). This increase was primarily due to $5.9 million in higher employee salaries and related costs between periods and $3.4 million of stock-based compensation incurred during the third quarter of 2017 versus none in the same prior year period. Employee-related costs were substantially higher during the third quarter of 2017 due to the number of administrative employees (i.e. non-billable to our joint interest partners) increasing from 29 at September 30, 2016 to 94 at September 30, 2017. These increases were partially offset by a decrease in transaction costs between periods. There were $1.1 million of Silver Run acquisition costs incurred during the third quarter of 2016, while no such costs were similarly incurred during the third quarter of 2017.

Other Income and Expenses.

Interest Expense. The following table summarizes our interest expenses for the periods indicated:



	Successor			Predecessor
(in thousands)	For the Three Months Ended September 30, 2017			For the Three Months Ended September 30, 2016
Credit facility	$	1,480		$	990
Term Loan	—			993
Interest capitalized	(465		)	—
Total	$	1,015		$	1,983

For the three months ended September 30, 2017 (Successor), we incurred $1.5 million in interest related to CRP’s credit facility of which $0.5 million was capitalized as it was utilized to fund the Company’s drilling and completion capital expenditures. For the three months ended September 30, 2016 (Predecessor), we recorded $1.0 million in interest related to CRP’s credit facility and $1.0 million in interest related to CRP’s term loan, which was extinguished upon the closing of the Business Combination. Our weighted average debt outstanding during the third quarter of 2017 was $108.5 million versus $124.0 million for the third quarter of 2016. Our weighted average effective interest rate was 3.77% during the third quarter of 2017 compared to 2.79% for the third 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 month periods ended September 30, 2017 (Successor) and 2016 (Predecessor), we recognized non-cash mark-to-market derivative losses of $1.3 million and $0.2 million, respectively. Cash derivative settlements, on the other hand, amounted to $0.4 million and $2.0 million in gains for both the third quarters of 2017 and 2016, respectively.

Income Tax Expense. During the three months ended September 30, 2017 (Successor) the Company recognized $8.2 million in income tax expense. The Company's provision for income taxes for the three months ended September 30, 2017 differed from the amount that would be provided by applying the statutory U.S. federal tax rate of 35% to pre-tax income primarily because of state income taxes and permanent differences.

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Nine Months Ended September 30, 2017 (Successor) Compared to Nine Months Ended September 30, 2016 (Predecessor)



	Successor			Predecessor		Increase/(Decrease)
	For the Nine Months Ended September 30, 2017			For the Nine Months Ended September 30, 2016		$			%
Net revenues (in thousands):
Oil sales	$	204,702		$	56,975	$	147,727		259	%
Natural gas sales	33,226			5,717		27,509			481	%
NGL sales	25,844			3,097		22,747			734	%
Total net revenues	$	263,772		$	65,789	$	197,983		301	%

Average sales prices:
Oil (per Bbl)	$	45.76		$	37.48	$	8.28		22	%
Effect of derivative settlements on average price (per Bbl)	0.12			15.30		(15.18		)	(99	)%
Oil net of hedging (per Bbl)	$	45.88		$	52.78	$	(6.90	)	(13	)%

Average NYMEX price for oil (per Bbl)	$	49.44		41.43		8.01			19	%

Natural gas (per Mcf)	$	2.78		$	2.24	$	0.54		24	%
Effect of derivative settlements on average price (per Mcf)	(0.02		)	—		(0.02		)	100	%
Natural gas net of hedging (per Mcf)	$	2.76		$	2.24	$	0.52		23	%

Average NYMEX price for natural gas (per Mcf)	$	3.05		2.34		0.71			30	%

NGL (per Bbl)	$	23.67		$	12.80	$	10.87		85	%

Net production:
Oil (MBbls)	4,473			1,520		2,953			194	%
Natural gas (MMcf)	11,938			2,551		9,387			368	%
NGL (MBbls)	1,092			242		850			351	%
Total (MBoe) ⁽¹⁾	7,554			2,187		5,367			245	%

Average daily net production volume:
Oil (Bbls/d)	16,384			5,547		10,837			195	%
Natural gas (Mcf/d)	43,729			9,310		34,419			370	%
NGL (Bbls/d)	3,999			883		3,116			353	%
Total (Boe/d) ⁽¹⁾	27,670			7,982		19,688			247	%


⁽¹⁾	Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

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Oil, Natural Gas and NGL Sales Revenues. Our total net revenues for the nine months of 2017 (Successor) were $198.0 million (or 301%) higher than total net revenues for the nine months 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 194%, 368% and 351%, respectively, between periods. The oil volume increase between periods resulted primarily from our drilling success in the Delaware Basin, as well as the producing properties we acquired in the Silverback and GMT Acquisitions, which collectively added 603 MBbls of net oil production to our nine months ended September 30, 2017 results. Since the third quarter of 2016, we have placed 49 operated wells on production in the Delaware Basin, which has added 2,826 MBbls of net oil production to the first nine months of 2017. The increase in our operated well count is attributable to the ramp up of our drilling program starting in the fourth quarter of 2016. These oil volume increases were partially offset by normal production declines across 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. Natural gas and NGL volumes were also impacted by the acreage we acquired from Silverback, which has a higher gas/oil ratio. During the nine months ended September 30, 2017, our production was made up of 41% natural gas and NGL volumes as compared to 31% in the same 2016 period.

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 nine months ended September 30, 2017 to the same 2016 period. Our average price for oil before the effects of hedging increased 22%, our average price for natural gas before the effects of hedging increased 24%, and our average price for NGLs increased 85% between periods. Of the 22% increase in our average realized oil price, 19% of such increase was related to higher average NYMEX crude prices between periods, and the remaining 3% was attributable to slightly narrower oil differentials in the first nine months of 2017. The 24% increase in our average realized natural gas price was similarly related to higher NYMEX prices between periods (NYMEX natural gas prices being up 30% between periods) which effect was partially offset by wider gas differentials experienced in the nine months ended September 30, 2017. Of the overall 85% 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 nine months ended September 30, 2016 to the comparable 2017 period. Additionally, NGL prices increased beginning in August 2016 as a result of lower transportation costs incurred by our gas processor due to the use of pipeline versus prior trucking alternatives.

Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:



	Successor		Predecessor		Increase/(Decrease)
	For the Nine Months Ended September 30, 2017		For the Nine Months Ended September 30, 2016		$			%
Operating Expenses (in thousands):
Lease operating expenses	$	26,924	$	10,295	$	16,629		162	%
Severance and ad valorem taxes	14,358		3,523		10,835			308	%
Gathering, processing and transportation expenses	22,572		4,375		18,197			416	%
Production costs per Boe:
Lease operating expenses	$	3.56	$	4.71	$	(1.15	)	(24	)%
Severance and ad valorem taxes	1.90		1.61		0.29			18	%
Gathering, processing and transportation expenses	2.99		2.00		0.99			50	%

Lease Operating Expenses. Our LOE for the nine months ended September 30, 2017 (Successor) increased $16.6 million compared to the comparable 2016 period (Predecessor). Higher LOE for the first nine months of 2017 was primarily related to a $12.6 million increase associated with a higher well count. We added 49 gross wells through successful drilling and 57 gross wells from the Silverback and GMT Acquisitions. In addition, workover activity increased $4.0 million between periods as a result of our higher well count. We had 65 gross operated horizontal wells as of September 30, 2016 as compared to 171 gross operated horizontal wells as of September 30, 2017.

Our LOE on a per Boe basis, on the other hand, decreased when comparing the nine months ended September 30, 2017 to the same 2016 period. LOE per Boe was $3.56 for the nine months ended September 30, 2017, which represents a decrease of $1.15 per Boe (or 24%) from the nine months ended September 30, 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.

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counties in which we operate. Severance and ad valorem taxes for the nine months ended September 30, 2017 (Successor) increased $10.8 million (or 308%) compared to the nine months ended September 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 consistent for the nine months ended September 30, 2017 and 2016 at 5.4%.

Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) for the nine months ended September 30, 2017 (Successor) increased $18.2 million compared to the same 2016 period (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 increased 50% from $2.00 for the nine months ended September 30, 2016 to $2.99 per Boe for the comparable 2017 period. 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 nine months ended September 30, 2017, and thus a higher proportion of our production during this 2017 period was subject to gas gathering and transportation charges as well as gas processing fees. On a natural gas and NGL volumes basis (i.e. excluding crude oil barrels) the Boe rate increased only 12% between periods from $6.56 to $7.32 for the nine months ended September 30, 2016 and 2017, respectively. This increase was primarily the result of a new firm transportation agreement we entered into in June 2017, which provides guaranteed pipeline capacity for the Company’s natural gas sales (refer to Note 13—Commitments and Contingencies for additional information on such agreement).

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



	Successor		Predecessor
(in thousands)	For the Nine Months Ended September 30, 2017		For the Nine Months Ended September 30, 2016
Depreciation, depletion and amortization	$	102,847	$	60,939
Depreciation, depletion and amortization per Boe	13.61		27.86

Our DD&A rate can fluctuate as a result of finding and development costs, acquisitions, impairments, as well as changes in proved reserves or proved developed reserves. For the nine months ended September 30, 2017 (Successor), DD&A expense amounted to $102.8 million, an increase of $41.9 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 resulted in $149.5 million of incremental DD&A expense being incurred during the first nine months of 2017. This increase was largely offset, however, by a $107.6 million reduction in DD&A expense that was attributable to significantly lower DD&A rates between periods.

On a Boe basis our overall DD&A rate of $13.61 for the nine months ended September 30, 2017 was 51% lower than the rate of $27.86 for the same period in 2016. The primary factor contributing to this lower DD&A rate was substantial additions to our proved reserves and proved developed reserves over the past 12 months, coupled with reasonable drilling and completion costs over that same time period.

Exploration Expense. The following table summarizes our exploration expenses for the periods indicated:



	Successor		Predecessor
(in thousands)	For the Nine Months Ended September 30, 2017		For the Nine Months Ended September 30, 2016
Stock-based compensation expense	$	1,132	$	—
Geological and geophysical costs	2,960		920
Exploration expense	$	4,092	$	920

Exploration increased $3.2 million for the nine months ended September 30, 2017 (Successor) compared to the same 2016 period (Predecessor). Exploration expense mainly consists of costs of topographical studies, G&G projects, and salaries and expenses of G&G personnel and consultants. The period over period increase in exploration expense is due to (i) seven geologist positions added since the third quarter of 2016, and (ii) equity-based compensation awards that were granted to G&G personnel in 2017 and during the 2016 Successor period that were not likewise granted as of September 30, 2016.

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General and Administrative Expenses. The following table summarizes our G&A expenses for the periods indicated:



	Successor		Predecessor
(in thousands)	For the Nine Months Ended September 30, 2017		For the Nine Months Ended September 30, 2016
Stock-based compensation expense	$	8,288	$	—
Cash general and administrative expenses	27,729		9,735
General and administrative expenses	$	36,017	$	9,735

G&A expenses for the nine months ended September 30, 2017 (Successor) increased $26.3 million over the same 2016 period (Predecessor). This increase was primarily due to $14.7 million in higher employee salaries and related costs between periods, $8.3 million of stock-based compensation incurred during the nine months ended September 30, 2017 versus none in the same prior year period, and $2.9 million in increased professional fees. Employee-related costs were substantially higher during the nine months ended September 30, 2017 due to the number of administrative employees (i.e. non-billable to our joint interest partners) increasing from 29 at September 30, 2016 to 94 as of September 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.

Gain on Sale of Oil and Natural Gas Properties. During the nine months ended September 30, 2017 (Successor), we recorded a gain on sale of oil and natural gas properties of $7.2 million primarily related to the sale of our Pecos County, Texas acreage.

Interest Expense. The following table summarizes our interest expenses for the periods indicated:



	Successor			Predecessor
(in thousands)	For the Nine Months Ended September 30, 2017			For the Nine Months Ended September 30, 2016
Credit facility	$	2,633		$	2,403
Term Loan	—			3,019
Interest capitalized	(501		)	—
Total	$	2,132		$	5,422

For the nine months ended September 30, 2017 (Successor), we incurred $2.6 million in interest related to CRP’s credit facility of which $0.5 million was capitalized as it was utilized to fund the Company’s drilling and completion capital expenditures. For the nine months ended September 30, 2016 (Predecessor), we recorded $2.4 million in interest related to CRP’s credit facility and $3.0 million on the term loan, which was extinguished upon closing of the Business Combination. Our weighted average debt outstanding for the nine months ended September 30, 2017 was $46.1 million versus $99.5 million for the same 2016 period. Our weighted average effective interest rate was 3.72% during the nine months ended September 30, 2017 compared to 2.67% for the comparable 2016 period.

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 nine months ended September 30, 2017 (Successor), we recognized non-cash mark-to-market derivative gains of $5.1 million compared to non-cash mark-to-market losses of $20.8 million for the same 2016 period (Predecessor). Cash derivative settlements amounted to $0.3 million and $16.6 million in gains for the nine months of 2017 and 2016, respectively.

Income Tax Expense. During the nine months ended September 30, 2017 (Successor) the Company recognized $17.3 million income tax expense. The Company's provision for income taxes for the nine months ended September 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 primarily 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 $17.3 million for the nine months ended September 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 25.6%.

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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 offerings of equity securities and, prior to the Business Combination, capital contributions from CRP’s Sponsors. To date, our primary use of capital has been for development and the acquisition of oil and natural gas properties.

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



(in millions)	Nine Months Ended September 30, 2017
Drilling and completion capital expenditures	$	398.4
Land and other	40.5
Facilities, seismic and other	11.3
Total capital expenditures	450.2

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. 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 future prices and cash flows to be generated from (i) new wells we drilled and completed in latter 2016 and plan to drill and complete in 2017, (ii) wells and locations we added from 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.

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 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 sources for funding capital investments. As we pursue our future development program, we are actively assessing the correct mix of reserve base borrowings and debt offerings. If we require additional capital to fund acquisitions, we may also seek such capital through traditional reserve base borrowings, offerings of debt and equity securities, asset sales or other means. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.

Working Capital Analysis

Our cash balances were $2.6 million and $134.1 million as of September 30, 2017 and December 31, 2016, respectively. Due to the amounts that we incur related to our drilling program, we may have temporary working capital deficits. However, we expect that our cash flows from operating activities and future borrowings under CRP’s credit facility or otherwise 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.

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Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor)

The following table summarizes our cash flows for the periods indicated:



	Successor			Predecessor
(in thousands)	For the Nine Months Ended September 30, 2017			For the Nine Months Ended September 30, 2016
Net cash provided by operating activities	$	137,150		$	51,511
Net cash used in investing activities	(766,754		)	(100,975		)
Net cash provided by financing activities	498,102			48,106

During the nine months ended September 30, 2017, we generated $137.2 million of cash provided by operating activities, an increase of $85.6 million from the same period in 2016. Cash provided by operating activities increased primarily due to higher net income as a results of increased crude oil, natural gas and NGL production volumes and higher realized sales prices for gas and NGLs as well as lower cash interest paid during the nine months ended September 30, 2017. These positive factors were partially offset by higher lease operating expenses, severance and ad valorem taxes, GP&T expenses, exploration costs, and cash G&A expenses during the nine months ended September 30, 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 nine months ended September 30, 2017, cash flows from operating activities, cash on hand and $130.0 million of net borrowings under our credit facility were used to finance $354.5 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 million in net borrowings under our credit facility, and proceeds from the sale of oil and gas properties were used to finance $419.5 million in oil and gas property acquisitions.

Revolving Credit Facility

CRP has a credit agreement with a syndicate of banks that as of September 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 September 30, 2017, the Company had $184.1 million in available borrowing capacity, which was net of $165.0 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, estimated cash flows from these reserves and its commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of permitted issued senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under its credit agreement. In connection with the October 2017 semi-annual redetermination, on November 2, 2017, the Company entered into the fifth amendment to the restated credit agreement to increase the borrowing base from $350.0 million to $575.0 million.

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 September 30, 2017, the weighted average interest rate on borrowings under CRP’s revolving credit facility was approximately 3.86%. 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. The credit facility provides for interest only payments until October 2019, when the credit agreement expires and all outstanding borrowings are due.

CRP’s credit agreement contains restrictive covenants that limit its ability to, among other things: incur additional indebtedness; make investments and loans; enter into mergers; make or declare dividends; enter into commodity hedges exceeding a specified percentage of our expected production; enter into interest rate hedges exceeding a specified percentage of

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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: (i) a current ratio, which is the ratio of CRP’s consolidated current assets (including unused commitments under its revolving credit facility and excluding non-cash assets under ASC 815 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 (ii) a leverage ratio, which is the ratio of Total Funded Debt (as defined in CRP’s credit agreement) to consolidated EBITDAX (as defined in CRP’s credit agreement) for the rolling four fiscal quarter period ending on such day, of not greater than 4.0 to 1.0.

CRP was in compliance with the covenants and the financial ratios described above as of September 30, 2017 and through the filing of this report.

Off-Balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

There have been no material changes during the nine months ended September 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 mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices and may partially limit our potential gains from future increases in prices. CRP’s credit agreement limits its ability to enter into commodity hedges covering greater than 80% of its reasonably anticipated projected production volume.

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



Description & Production Period	Volume (Bbl)	Weighted Average Fixed Price/Differential ($/Bbl) ⁽¹⁾
Crude Oil Swaps:
October 2017 - December 2017	23,000	$	64.05
October 2017 - December 2017	9,200	54.65
October 2017 - December 2017	9,200	43.50
October 2017 - December 2017	9,200	44.85
October 2017 - December 2017	9,200	45.10
October 2017 - December 2017	27,600	44.80
October 2017 - December 2017	9,200	47.27
October 2017 - December 2017	9,200	49.00
October 2017 - December 2017	46,000	49.80
October 2017 - December 2017	18,400	52.35
January 2018 - December 2018	36,500	55.95
Crude Oil Basis Swaps:
October 2017 - November 2017	15,250	$	(0.20	)
October 2017 - November 2017	6,100	(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 swap contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period.

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Description & Production Period	Volume (MMBtu)	Weighted Average Fixed Price/Differential ($/MMBtu) ⁽¹⁾
Natural Gas Swaps:
October 2017 - December 2017	368,000	$	2.94
Natural Gas Basis Swaps:
January 2018 - December 2018	1,825,000	$	(0.43	)
January 2019 - December 2019	1,825,000	$	(0.43	)


⁽¹⁾	The natural gas swap contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas. The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and the NYMEX price of Natural Gas during the relevant calculation period.

The fair value of these commodity derivative instruments at September 30, 2017 was a net asset of $0.2 million. A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of September 30, 2017 would cause a $1.1 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 September 30, 2017 would cause a $0.1 million increase or decrease, respectively, in this fair value liability.

Interest Rate Risk

At September 30, 2017, we had $165.0 million of debt outstanding, with a weighted average interest rate of 3.86%. 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 $1.7 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 September 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 September 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 September 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 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
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).
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:	November 6, 2017

Permian Resources - 10-Q quarterly report FY2017 Q3

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