UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ ~~QUARTERLY REPORT PURSUANT TO SECTION~~Quarterly report pursuant to Section 13 ORor 15(d) ~~OF THE SECURITIES EXCHANGE ACT OF~~of the Securities Exchange Act of 1934

For the quarterly period ended ~~September 30, 2019~~March 31, 2020

☐ ~~TRANSITION REPORT PURSUANT TO SECTION~~Transition report pursuant to Section 13 ORor 15(d) ~~OF THE SECURITIES EXCHANGE ACT OF~~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)~~No.)

1001 Seventeenth Street, Suite 1800

Denver, Colorado80202

(Registrant’s telephone number, including area code): (720) 499-1400

~~(Registrant’s Telephone Number, Including Area Code)~~

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, par value $0.0001 per share	CDEV	The NASDAQ Stock Market LLC

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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

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	Accelerated filer	Non-accelerated filer	Smaller reporting company	Emerging growth company
☒	☐	☐	☐	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of ~~October 31, 2019,~~April 30, 2020, there were ~~275,600,503~~277,082,141 shares of Class A ~~Common Stock, par value $0.0001 per share and 1,143,039 shares of Class C~~ Common Stock, par value $0.0001 per share outstanding.

TABLE OF CONTENTS



		Page
Glossary of Oil and Natural Gas Terms		3

Glossary of Certain Other Terms		5

Cautionary Statement Concerning Forward-Looking Statements		6

Part I—FINANCIAL INFORMATION		8

Item 1.	Financial Statements (Unaudited)	8

	Consolidated Balance Sheets as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018~~2019	8

	Consolidated Statements of Operations for the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~	9

	Consolidated Statements of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~	10

	Consolidated Statements of Shareholders’ Equity for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~	12

	Notes to Consolidated Financial Statements	1413

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4341

Item 4.	Controls and Procedures	4543

Part II—OTHER INFORMATION		4543

Item 1.	Legal Proceedings	4543

Item 1A.	Risk Factors	45

~~Item 5.~~	~~Other Information~~	4543

Item 6.	Exhibits	4647

Signatures		4748

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this Quarterly Report on Form 10-Q, which are commonly used in the oil and natural gas industry:

Bbl. One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.

Bbl/d. One Bbl per day.

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

Boe/d. One Boe per day.

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

Completion. The process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to optimize production.

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

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Flush production. First yield from a flowing oil well during its most productive period after it is first completed and put on line.

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

LIBOR. London Interbank Offered Rate.

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

MBoe. One thousand Boe.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One Mcf per day.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

NGL. Natural gas liquids. These are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline, that can be collectively removed from produced natural gas, separated into these substances and sold.

NYMEX. The New York Mercantile Exchange.

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

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.

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

Proved undeveloped reserves or PUD. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion or recompletion.

Realized price. The cash market price less differentials.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.

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

Royalty interest. An interest in an oil or gas property entitling the owner to shares of the production free of costs of exploration, development and production operations.

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

Wellbore. The hole drilled by a drill bit that is equipped for oil and natural gas production once the well has been completed. Also called well or borehole.

Working interest. The interest in an oil and gas property (typically a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

Workover. Operations on a producing well to restore or increase production.

WTI. West Texas Intermediate is a grade of crude oil used as a benchmark in oil pricing.

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 legacy owners of CRP, who sold approximately 89% of the outstanding membership interests in CRP to the Company in connection with the Business Combination. As of March 31,2020, the Centennial Contributors’ ownership interest in CRP was approximately 0.4%.

The Company, we, our or us. (i) Centennial Resource Development, Inc. and its consolidated subsidiaries including CRP, following the closing of the Business Combination and (ii) Silver Run Acquisition Corporation prior to the closing of the Business Combination.

Class A Common Stock. Our Class A Common Stock, par value $0.0001 per share.

Class C Common Stock. Our Class C Common Stock, par value $0.0001 per share, which was issued to the Centennial Contributors in connection with the Business Combination.

Contribution Agreement. The Contribution Agreement, dated as of July 6, 2016, among the Centennial Contributors, CRP and NewCo, as amended by Amendment No. 1 thereto, dated as of July 29, 2016, and the Joinder Agreement, dated as of October 7, 2016, by the Company.

~~CRD. Centennial Resource Development, LLC, a Delaware limited liability company, which was dissolved on June 15, 2018.~~

CRP. Centennial Resource Production, LLC, a Delaware limited liability company.

CRP Common Units. The units representing common membership interests in CRP.

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.~~

Riverstone. Riverstone Investment Group LLC and its affiliates, including Silver Run Sponsor, LLC, a Delaware limited liability company, collectively.

Voting common stock. Our Class A Common Stock and Class C Common Stock.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,” “plan,” “target” 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 this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 (the ~~“2018~~“2019 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:

volatility of oil, natural gas and NGL prices or a prolonged period of low oil, natural gas or NGL prices and the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”), such as Saudi Arabia, and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil;

the effects of excess supply of oil and natural gas resulting from the reduced demand caused by the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;

our business strategy and future drilling plans;

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

our drilling prospects, inventories, projects and programs;

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

our realized oil, natural gas and NGL prices;

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

our hedging strategy and results;

our competition and government regulations;

our ability to obtain permits and governmental approvals;

our pending legal or environmental matters;

the marketing and transportation of our oil, natural gas and NGLs;

our leasehold or business acquisitions;

cost of developing our properties;

our anticipated rate of return;

general economic conditions;

credit markets;

uncertainty regarding our future operating results; and

our plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

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 this Quarterly Report and in our ~~2018~~2019 Annual Report. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be

achieved or occur, and actual results could differ materially and adversely from those anticipated or implied by the forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

All forward-looking statements, expressed or implied, are made only as of the date of this Quarterly Report. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements to reflect events or circumstances after the date of this Quarterly Report.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

CENTENNIAL RESOURCE DEVELOPMENT, INC.

CONSOLIDATED BALANCE SHEETS (unaudited)

(in thousands, except share and per share amounts)

September 30, 2019 December 31, 2018
ASSETS
Current assets
Cash and cash equivalents $ 10,933
$ 18,157
Accounts receivable, net 141,312
100,623
Derivative instruments —
1,632
Prepaid and other current assets 8,931
9,777
Total current assets 161,176
130,189
Property and Equipment
Oil and natural gas properties, successful efforts method
Unproved properties 1,515,458
1,680,065
Proved properties 3,704,555
2,895,280
Accumulated depreciation, depletion and amortization (809,979 ) (496,900)
Total oil and natural gas properties, net 4,410,034
4,078,445
Other property and equipment, net 14,799
8,837
Total property and equipment, net 4,424,833
4,087,282
Noncurrent assets
Operating lease right-of-use assets 17,182
—
Other noncurrent assets 42,940
42,550
TOTAL ASSETS $ 4,646,131
$ 4,260,021

LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses $ 267,962
$ 240,575
Derivative instruments 4,433
6,051
Operating lease liabilities 14,151
—
Other current liabilities 942
1,090
Total current liabilities 287,488
247,716
Noncurrent liabilities
Long-term debt, net 1,001,867
691,630
Asset retirement obligations 14,629
13,895
Deferred income taxes 84,471
62,167
Operating lease liabilities 3,862
—
Other long-term liabilities —
744
Total liabilities 1,392,317
1,016,152
Commitments and contingencies (Note 11)

Shareholders’ equity
Preferred stock, $0.0001 par value, 1,000,000 shares authorized:
Series A: 1 share issued and outstanding —
—
Common stock, $0.0001 par value, 620,000,000 shares authorized:
Class A: 280,443,894 shares issued and 275,556,804 shares outstanding at September 30, 2019 and 265,859,273 shares issued and 264,323,328 shares outstanding at December 31, 2018 28
27
Class C (Convertible): 1,143,039 shares issued and outstanding at September 30, 2019 and 12,003,183 shares issued and outstanding at December 31, 2018 —
1
Additional paid-in capital 2,967,149
2,833,611
Retained earnings 272,718
266,538
Total shareholders’ equity 3,239,895
3,100,177
Noncontrolling interest 13,919
143,692
Total equity 3,253,814
3,243,869
TOTAL LIABILITIES AND EQUITY $ 4,646,131
$ 4,260,021



	March 31, 2020			December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	3,841		$	10,223
Accounts receivable, net	62,892			101,912
Prepaid and other current assets	6,997			7,994
Total current assets	73,730			120,129
Property and Equipment
Oil and natural gas properties, successful efforts method
Unproved properties	1,350,287			1,470,903
Proved properties	4,238,784			3,962,175
Accumulated depreciation, depletion and amortization	(1,623,671		)	(931,737)
Total oil and natural gas properties, net	3,965,400			4,501,341
Other property and equipment, net	14,240			14,612
Total property and equipment, net	3,979,640			4,515,953
Noncurrent assets
Operating lease right-of-use assets	8,333			11,841
Other noncurrent assets	44,547			40,365
TOTAL ASSETS	$	4,106,250		$	4,688,288

LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	223,651		$	244,309
Derivative instruments	8,777			325
Operating lease liabilities	6,440			9,232
Other current liabilities	177			600
Total current liabilities	239,045			254,466
Noncurrent liabilities
Long-term debt, net	1,117,919			1,057,389
Asset retirement obligations	17,651			16,874
Deferred income taxes	2,296			85,504
Operating lease liabilities	2,552			3,354
Total liabilities	1,379,463			1,417,587
Commitments and contingencies (Note 11)
Shareholders’ equity
Preferred stock, $0.0001 par value, 1,000,000 shares authorized:
Series A: 1 share issued and outstanding	—			—
Common stock, $0.0001 par value, 620,000,000 shares authorized:
Class A: 281,530,821 shares issued and 276,037,796 shares outstanding at March 31, 2020 and 280,650,341 shares issued and 275,811,346 shares outstanding at December 31, 2019	28			28
Class C (Convertible): 1,034,119 shares issued and outstanding at March 31, 2020 and December 31, 2019	—			—
Additional paid-in capital	2,982,187			2,975,756
Retained earnings (accumulated deficit)	(265,647		)	282,336
Total shareholders’ equity	2,716,568			3,258,120
Noncontrolling interest	10,219			12,581
Total equity	2,726,787			3,270,701
TOTAL LIABILITIES AND EQUITY	$	4,106,250		$	4,688,288

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

CENTENNIAL RESOURCE DEVELOPMENT, INC.

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


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Operating revenues
Oil and gas sales	$	229,130		$	234,880		$	687,938		$	668,541		$	192,769		$	214,569
Operating expenses
Lease operating expenses	42,330			23,706			107,077			59,164			32,639			29,862
Severance and ad valorem taxes	12,213			14,410			45,519			42,791			16,573			16,120
Gathering, processing and transportation expenses	20,853			16,090			52,120			45,214			16,939			15,024
Depreciation, depletion and amortization	112,720			83,423			321,392			224,379			101,258			96,558
Impairment and abandonment expense	6,745			8,612			42,427			10,396			611,300			31,264
Exploration expense	2,869			2,712			9,246			8,026			4,009			2,516
General and administrative expenses	20,036			16,561			56,589			44,667			18,870			18,118
Total operating expenses	217,766			165,514			634,370			434,637			801,588			209,462
Net gain (loss) on sale of long-lived assets	(22		)	52			(15		)	(74		)	245			(2		)
Income from operations	11,342			69,418			53,553			233,830
Income (loss) from operations													(608,574		)	5,105

Other income (expense)
Interest expense	(15,246		)	(6,534		)	(39,843		)	(18,138		)	(16,421		)	(10,160		)
Net gain (loss) on derivative instruments	1,522			(9,571		)	(2,221		)	14,969			(8,505		)	(5,871		)
Other income (expense)	62			13			321			(4		)	(53		)	126
Total other income (expense)	(13,662		)	(16,092		)	(41,743		)	(3,173		)	(24,979		)	(15,905		)

Income (loss) before income taxes	(2,320		)	53,326			11,810			230,657			(633,553		)	(10,800		)
Income tax expense	(1,393		)	(11,652		)	(5,058		)	(50,729		)
Income tax benefit													83,208			2,263
Net income (loss)	(3,713		)	41,674			6,752			179,928			(550,345		)	(8,537		)
Less: Net income (loss) attributable to noncontrolling interest	(128		)	2,386			572			11,009
Less: Net (income) loss attributable to noncontrolling interest													2,362			425
Net income (loss) attributable to Class A Common Stock	$	(3,585	)	$	39,288		$	6,180		$	168,919		$	(547,983	)	$	(8,112	)

Income (loss) per share of Class A Common Stock:
Basic	$	(0.01	)	$	0.15		$	0.02		$	0.64		$	(1.99	)	$	(0.03	)
Diluted	$	(0.01	)	$	0.15		$	0.02		$	0.63		$	(1.99	)	$	(0.03	)

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

CENTENNIAL RESOURCE DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)


	For the Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2020			2019
Cash flows from operating activities:
Net income	$	6,752		$	179,928
Net income (loss)							$	(550,345	)	$	(8,537	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	321,392			224,379			101,258			96,558
Stock-based compensation expense	21,351			14,329			6,409			6,483
Impairment and abandonment expense	42,427			10,396			611,300			31,264
Exploratory dry hole costs	—			395
Deferred tax expense	5,058			50,729
Net loss on sale of long-lived assets	15			74
Deferred tax benefit							(83,208		)	(2,263		)
Net (gain) loss on sale of long-lived assets							(245		)	2
Non-cash portion of derivative (gain) loss	14			(579		)	8,452			5,494
Amortization of debt issuance costs and discount	2,070			1,258			799			512
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(47,771		)	(18,327		)	41,026			(18,708		)
(Increase) decrease in prepaid and other assets	(995		)	(52		)	(263		)	(205		)
Increase (decrease) in accounts payable and other liabilities	34,562			32,165			(34,365		)	(9,572		)
Net cash provided by operating activities	384,875			494,695			100,818			101,028
Cash flows from investing activities:
Acquisition of oil and natural gas properties	(73,346		)	(114,870		)	(5,795		)	(25,691		)
Drilling and development capital expenditures	(644,945		)	(723,100		)	(161,895		)	(217,158		)
Purchases of other property and equipment	(8,207		)	(4,409		)	(486		)	(1,738		)
Proceeds from sales of oil and natural gas properties	28,378			147,413			1,200			25,709
Net cash used in investing activities	(698,120		)	(694,966		)	(166,976		)	(218,878		)
Cash flows from financing activities:
Proceeds from borrowings under revolving credit facility	345,000			295,000			195,000			130,000
Repayment of borrowings under revolving credit facility	(525,000		)	(155,000		)	(135,000		)	(430,000		)
Proceeds from issuance of 2027 Senior Notes	496,175			—
Proceeds from issuance of Senior Notes							—			496,175
Debt issuance costs	(7,200		)	(4,217		)	—			(6,698		)
Proceeds from exercise of stock options	—			847
Restricted stock used for tax withholdings	(911		)	(1,119		)	(208		)	(291		)
Net cash provided by financing activities	308,064			135,511			59,792			189,186
Net decrease in cash, cash equivalents and restricted cash	(5,181		)	(64,760		)
Net increase (decrease) in cash, cash equivalents and restricted cash							(6,366		)	71,336
Cash, cash equivalents and restricted cash, beginning of period	21,422			125,915			15,543			21,422
Cash, cash equivalents and restricted cash, end of period	$	16,241		$	61,155		$	9,177		$	92,758

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

CENTENNIAL RESOURCE DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (Continued)
(in thousands)


	For the Nine Months Ended September 30,				Three Months Ended March 31,
	2019		2018		2020			2019
Supplemental cash flow information
Cash paid for interest	$	27,985	$	15,587	$	12,977		$	15,210
Operating lease liability payments:
Cash used in operating activities	16,808		—		2,657			4,905
Cash used in investing activities	13,946		—		2,019			5,682
Supplemental non-cash activity
Accrued capital expenditures included in accounts payable and accrued expenses	$	120,238	$	97,844	$	108,282		$	136,113
Asset retirement obligations incurred, including revisions to estimates	1,075		1,040		413			264
Right-of-use assets obtained in exchange for operating lease liabilities	35,686		—
Right-of-use assets recognized (derecognized) with offsetting operating lease liabilities					(829		)	34,385

Reconciliation of cash, cash equivalents and restricted cash presented on the Consolidated Statements of Cash Flows for the periods presented:


	For the Nine Months Ended September 30,				Three Months Ended March 31,
	2019		2018		2020		2019
Cash and cash equivalents	$	10,933	$	58,922	$	3,841	$	89,482
Restricted cash⁽¹⁾	5,308		2,233		5,336		3,276
Total cash, cash equivalents and restricted cash	$	16,241	$	61,155	$	9,177	$	92,758


⁽¹⁾	Included in Prepaid and other current assets and Other noncurrent assets line items onin the Consolidated Balance Sheets.

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

CENTENNIAL RESOURCE DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)

(in thousands)


	Common Stock									Preferred Stock																					Common Stock								Preferred Stock
	Class A				Class C					Series A			Additional Paid-In Capital				Retained Earnings				Total Shareholder's Equity			Non-controlling Interest				Total Equity			Class A				Class C				Series A			Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Total Shareholder's Equity			Non-controlling Interest			Total Equity
	Shares		Amount		Shares		Amount			Shares	Amount						Retained Earnings			Shares				Non-controlling Interest			Amount					Shares		Amount		Shares		Amount				Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Total Shareholder's Equity			Non-controlling Interest			Total Equity
Balance at December 31, 2018	265,859		$	27	12,003		$	1		—	$	—	Additional Paid-In Capital			$	2,833,611			$	Total Shareholder's Equity	266,538		$	3,100,177			Total Equity		$	143,692		$	3,243,869
Restricted stock issued	436		—		—		—			—	—		—				—				—			—				—
Restricted stock used for tax withholding	(24	)	—		—		—			—	—		(291		)		—				(291		)	—				(291		)
Stock-based compensation	—		—		—		—			—	—		6,483				—				6,483			—				6,483
Net income (loss)	—		—		—		—			—	—		—				(8,112		)		(8,112		)	(425		)		(8,537		)
Balance at March 31, 2019	266,271		$	27	12,003		$	1		—	$	—	$	2,839,803			$	258,426			$	3,098,257		$	143,267			$	3,241,524
Balance at December 31, 2019																															280,650		$	28	1,034		$	—	—	$	—	$	2,975,756		$	282,336		$	3,258,120		$	12,581		$	3,270,701
Restricted stock issued	4		—		—		—			—	—		—				—				—			—				—			1,305		—		—		—		—	—		—			—			—			—			—
Restricted stock forfeited	(16	)	—		—		—			—	—		—				—				—			—				—			(406	)	—		—		—		—	—		—			—			—			—			—
Restricted stock used for tax withholding	(4	)	—		—		—			—	—		(41		)		—				(41		)	—				(41		)	(78	)	—		—		—		—	—		(208		)	—			(208		)	—			(208		)
Issuance of Class A common stock under Employee Stock Purchase Plan																															59		—		—		—		—	—		230			—			230			—			230
Stock-based compensation	—		—		—		—			—	—		6,758				—				6,758			—				6,758			—		—		—		—		—	—		6,409			—			6,409			—			6,409
Net income (loss)	—		—		—		—			—	—		—				17,877				17,877			1,125				19,002			—		—		—		—		—	—		—			(547,983		)	(547,983		)	(2,362		)	(550,345		)
Balance at June 30, 2019	266,255		$	27	12,003		$	1		—	$	—	$	2,846,520			$	276,303			$	3,122,851		$	144,392			$	3,267,243
Restricted stock issued	3,466		—		—		—			—	—		—				—				—			—				—
Restricted stock forfeited	(30	)	—		—		—			—	—		—				—				—			—				—
Restricted stock used for tax withholding	(107	)	—		—		—			—	—		(579		)		—				(579		)	—				(579		)
Stock-based compensation	—		—		—		—			—	—		8,110				—				8,110			—				8,110
Conversion of common stock from Class C to Class A, net of tax	10,860		1		(10,860	)	(1		)	—	—		113,098				—				113,098			(130,345		)		(17,247		)
Net income (loss)	—		—		—		—			—	—		—				(3,585		)		(3,585		)	(128		)		(3,713		)
Balance at September 30, 2019	280,444		$	28	1,143		$	—		—	$	—	$	2,967,149			$	272,718			$	3,239,895		$	13,919			$	3,253,814
Balance at March 31, 2020																															281,530		$	28	1,034		$	—	—	$	—	$	2,982,187		$	(265,647	)	$	2,716,568		$	10,219		$	2,726,787



Balance at December 31, 2018	265,859		$	27	12,003	$	1	—	$	—	$	2,833,611		$	266,538		$	3,100,177		$	143,692		$	3,243,869
Restricted stock issued	436		—		—	—		—	—		—			—			—			—			—
Restricted stock forfeited	—		—		—	—		—	—		—			—			—			—			—
Restricted stock used for tax withholding	(24	)	—		—	—		—	—		(291		)	—			(291		)	—			(291		)
Stock-based compensation	—		—		—	—		—			6,483			—			6,483			—			6,483
Net income (loss)	—		—		—	—		—	—		—			(8,112		)	(8,112		)	(425		)	(8,537		)
Balance at March 31, 2019	266,271		$	27	12,003	$	1	—	$	—	$	2,839,803		$	258,426		$	3,098,257		$	143,267		$	3,241,524

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

~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited) (Continued)~~

~~(in thousands)~~

Common Stock Preferred Stock
Class A Class C Series A Additional Paid-In Capital Retained Earnings Total Shareholder's Equity Non-controlling Interest Total Equity
Shares Amount Shares Amount Shares Amount
Balance at December 31, 2017 261,338
$ 26
15,661
$ 2
—
$ —
$ 2,767,558
$ 66,639
$ 2,834,225
$ 169,747
$ 3,003,972
Restricted stock issued 199
—
—
—
—
—
—
—
—
—
—
Restricted stock forfeited (26 ) —
—
—
—
—
—
—
—
—
—
Restricted stock used for tax withholding (10 ) —
—
—
—
—
(192 ) —
(192 ) —
(192 )
Stock option exercises 10
—
—
—
—
—
164
—
164
—
164
Stock-based compensation —
—
—
—
—
—
4,333
—
4,333
—
4,333
Conversion of common stock from Class C to Class A, net of tax 3,347
1
(3,347 ) (1 ) —
—
42,188
—
42,188
(35,519 ) 6,669
Net income (loss) —
—
—
—
—
—
—
66,090
66,090
4,682
70,772
Balance at March 31, 2018 264,858
$ 27
12,314
$ 1
—
$ —
$ 2,814,051
$ 132,729
$ 2,946,808
$ 138,910
$ 3,085,718
Restricted stock issued 23
—
—
—
—
—
—
—
—
—
—
Restricted stock forfeited (17 ) —
—
—
—
—
—
—
—
—
—
Restricted stock used for tax withholding (4 ) —
—
—
—
—
(65 ) —
(65 ) —
(65 )
Stock option exercises 28
—
—
—
—
—
411
—
411
—
411
Stock-based compensation —
—
—
—
—
—
4,655
—
4,655
—
4,655
Net income (loss) —
—
—
—
—
—
—
63,541
63,541
3,941
67,482
Balance at June 30, 2018 264,888
$ 27
12,314
$ 1
—
$ —
$ 2,819,052
$ 196,270
$ 3,015,350
$ 142,851
$ 3,158,201
Restricted stock issued 697
—
—
—
—
—
—
—
—
—
—
Restricted stock forfeited (93 ) —
—
—
—
—
—
—
—
—
—
Restricted stock used for tax withholding (46 ) —
—
—
—
—
(862 ) —
(862 ) —
(862 )
Stock option exercises 14
—
—
—
—
—
272
—
272
—
272
Stock-based compensation —
—
—
—
—
—
5,341
—
5,341
—
5,341
Conversion of common stock from Class C to Class A, net of tax 311
—
(311 ) —
—
—
3,953
—
3,953
(3,373 ) 580
Net income (loss) —
—
—
—
—
—
—
39,288
39,288
2,386
41,674
Balance at September 30, 2018 265,771
$ 27
12,003
$ 1
—
$ —
$ 2,827,756
$ 235,558
$ 3,063,342
$ 141,864
$ 3,205,206

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

CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Basis of Presentation and Summary of Significant Accounting Policies

Description of Business

Centennial Resource Development, Inc. is an independent oil and natural gas company focused on the development of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. The Company’s assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, and its properties consist of large, contiguous acreage blocks ~~primarily~~located in West Texas and New Mexico. Unless otherwise specified or the context otherwise requires, all references in these notes to “Centennial” or the “Company” are to Centennial Resource Development, Inc. and its consolidated subsidiary, Centennial Resource Production, LLC (“CRP”).

Principles of Consolidation and Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and the rules and regulations of the United States Securities and Exchange Commission (“SEC”) for interim financial reporting. Accordingly, certain disclosures normally included in an Annual Report on Form 10-K have been omitted. The consolidated financial statements and related notes included in this Quarterly Report should be read in conjunction with the Company’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the period ended December 31, ~~2018~~2019 (the ~~“2018~~“2019 Annual Report”). Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company’s ~~2018~~2019 Annual Report.

In the opinion of management, all normal, recurring adjustments and accruals considered necessary to present fairly, in all material respects, the Company’s interim financial results have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year.

The consolidated financial statements include the accounts of the Company and its majority owned subsidiary CRP, and CRP’s wholly-owned subsidiaries. ~~All intercompany balances and transactions have been eliminated in consolidation.~~ Noncontrolling interest represents third-party ownership in CRP and it is presented as a component of equity. ~~See~~ ~~Note 8—Noncontrolling Interest~~ ~~for further discussion~~As of March 31, 2020 and December 31, 2019, the noncontrolling ~~interest.~~interest ownership of CRP was 0.4%.

Use of Estimates

The preparation of the Company’s consolidated financial statements requires the Company’s management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events, and accordingly, actual results could differ from amounts previously established.

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

Income Taxes

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to the Company’s year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various state jurisdictions, permanent and temporary differences and the likelihood of recovering deferred tax assets generated. The accounting estimates used to compute the provision for income taxes may change as new events occur, additional information becomes known or as the tax environment changes.

As of March 31, 2020, the Company determined that it is more-likely-than-not that a portion of its deferred tax assets will not be realized. Accordingly, a valuation allowance against its deferred tax assets in the amount of $55.6 million was recognized as of March 31, 2020, which caused the Company’s provision for income taxes for the three months ended March 31, 2020 to differ from the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book loss.

1413

Table of Contents

CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~Recently Issued or Adopted Accounting Standards~~Risks and Uncertainties

~~In August 2018,~~The prices received for oil, natural gas and NGL production heavily influences the ~~Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-13,~~ ~~Disclosure Framework - Changes~~Company’s revenue, profitability, liquidity, access to capital, future rate of growth and carrying value of its properties. Oil, natural gas and NGLs are commodities, and their prices have been volatile in response to recent changes in global and domestic supply, the ~~Disclosure Requirements for Fair Value Measurement, which updates the disclosure requirements for fair value measurements in Accounting Standard Codification (“ASC”) Topic 820,~~ ~~Fair Value Measurement~~ (“ASC Topic 820”). Certain disclosure requirements under ASC Topic 820 were removed, modified or added in order to improve the effectiveness of the fair value note included in the financial statements. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2019, including interim periods within those fiscal years. An entity is permitted to early adopt any removed or modified disclosuresglobal COVID-19 pandemic and ~~delay adoption of the additional disclosures until the effective date.~~demand and market uncertainty. The Company ~~is currently assessing the impact~~generally funds its operations and capital expenditures with its cash flows from operations, borrowings under CRP’s credit agreement, and offerings of ~~this update on the Company's consolidated financial statements.~~

~~In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases, which created ASC Topic 842,~~ ~~Leases~~ ~~(“ASC Topic 842”), superseding current lease requirements under ASC Topic 840,~~ ~~Leases. Subsequently in 2018, the FASB issued various ASUs which provide a practical expedient for the evaluation of existing land easement agreements, optionality in the adoption transition method,~~debt and additional implementation guidance. ASC Topic 842 and its related amendments apply to any entity that enters into a lease, with some specified scope exemptions. Under ASC Topic 842, a lessee should recognize in its consolidated balance sheet 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 lessor accounting, changes were made to align key aspects with revenue recognition guidance. ASC Topic 842 was effective for public entities for fiscal years, beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted.

The standard permits retrospective application using either of the following methodologies: (i) application of the new standard at the earliest presented period or (ii) application of the new standard at the adoption date with a cumulative-effect adjustment recognized to retained earnings.equity securities. The Company ~~has adopted this guidance as~~expects to be able to fund its operations, planned capital expenditures and working capital requirements during the next 12 months and the foreseeable future. However, continued volatility of ~~January 1, 2019~~oil and ~~elected to recognize a cumulative-effect adjustment at the time of adoption. The Company has elected the following practical expedients that allow~~gas prices could have an entity to carry forward historical accounting treatment relating to: (i) lease identification and classification for existing leases and (ii) existing land easements. The adoption of ASC 842 resulted in the recognition of ~~Operating lease right-of-use assets~~ an~~d Operating lease liabilities~~ in the Company’s Consolidated Balance Sheets for its existing operating leases including drilling rig contracts, office rental agreements, and other wellhead equipment. This adoption did not have a significant impactadverse effect on the Company’s ~~Consolidated Statements~~future business, financial condition, results of ~~Operations or Consolidated Statements~~operations, operating cash flows, liquidity and quantities of ~~Cash Flows. Refer~~oil and gas reserves that may be economically produced, which could in turn impact the Company’s ability to ~~Note 13—Leases~~ ~~for~~comply with the financial covenants under CRP’s credit agreement and the Senior Notes which could also limit the amount of borrowings available to fund the Company’s capital expenditures and potential acquisitions. Additionally, if forward prices decline, the Company could incur additional ~~information.~~impairments of its oil and gas assets and be subject to negative impacts to its production levels.

Note 2—Property Divestiture

On February 24, 2020, the Company entered into a purchase and sale agreement to sell its water disposal assets for a base sale price of approximately $150.0 million in cash at closing with up to an additional $75.0 million in deferred incentive payments based on future drilling activity (all amounts being subject to post-closing adjustments). The water disposal assets include certain saltwater disposal wells and the associated water infrastructure located in Reeves and Ward counties in Texas. The original closing date of the sale was March 31, 2020, however, the transaction has been delayed. While the transaction currently remains pending, either party may terminate the transaction if closing does not occur on or before May 15, 2020.

The purchase and sale agreement required the purchaser to deposit $10.0 million of cash in an escrow account. This amount will be applied to the sales price upon closing, or alternatively, it will be distributed to the Company or the purchaser in accordance with the remedy provisions of the purchase and sale agreement, if the agreement is terminated prior to closing.

Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses

Accounts receivable are comprised of the following:


(in thousands)	September 30, 2019		December 31, 2018		March 31, 2020		December 31, 2019
Accrued oil and gas sales receivable, net	$	71,732	$	66,997	$	36,105	$	76,578
Joint interest billings, net	65,444		31,658		26,530		25,136
Other	4,136		1,968		257		198
Accounts receivable, net	$	141,312	$	100,623	$	62,892	$	101,912

Accounts payable and accrued expenses are comprised of the following:


(in thousands)	September 30, 2019		December 31, 2018		March 31, 2020		December 31, 2019
Accounts payable	$	33,455	$	55,984	$	50,659	$	21,484
Accrued capital expenditures	94,952		75,791		70,241		83,002
Revenues payable	85,275		63,399		51,729		82,539
Accrued interest	24,162		11,129		22,563		19,405
Accrued employee compensation and benefits	9,699		9,757		4,906		12,979
Accrued expenses and other	20,419		24,515		23,553		24,900
Accounts payable and accrued expenses	$	267,962	$	240,575	$	223,651	$	244,309

1514

Table of Contents

CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 3—4—Long-Term Debt

The following table provides information about the Company’s long-term debt as of the dates indicated:


(in thousands)	September 30, 2019			December 31, 2018			March 31, 2020			December 31, 2019
Credit Facility due 2023	$	120,000		$	300,000		$	235,000		$	175,000

5.375% Senior Notes due 2026	400,000			400,000			400,000			400,000
6.875% Senior Notes due 2027	500,000			—			500,000			500,000
Unamortized debt issuance costs on Senior Notes							(13,626		)	(14,061		)
Unamortized debt discount	(3,643		)	—			(3,455		)	(3,550		)
Unamortized debt issuance costs on Senior Notes	(14,490		)	(8,370		)
Senior Notes, net	881,867			391,630			882,919			882,389

Total long-term debt, net	$	1,001,867		$	691,630		$	1,117,919		$	1,057,389

Credit Agreement

On May 4, 2018, CRP, the Company’s consolidated subsidiary, entered into an amended and restated credit agreement with a syndicate of banks that as of ~~September 30, 2019,~~March 31, 2020, had a borrowing base of $1.2 billion and elected commitments of $800.0 million. The credit agreement provides for a five-year secured revolving credit facility, maturing on May 4, 2023. As of ~~September 30, 2019,~~March 31, 2020, the Company had ~~$120.0~~$235.0 million in borrowings outstanding and ~~$679.2~~$564.2 million in available borrowing capacity, which was net of $0.8 million in letters of credit outstanding. Refer to Note 14—Subsequent Events for additional information on the spring 2020 redetermination and the amendments to the credit facility, inclusive of its redetermined borrowing base and corresponding level of elected commitments.

The amount available to be borrowed under ~~the Company’s~~CRP’s credit agreement is equal to the lesser of (i) the borrowing base, (ii) aggregate elected commitments, or (iii) $1.5 billion. The borrowing base is redetermined semi-annually in the spring and fall by the lenders in their sole discretion. It also allows for 2 optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the quantities of CRP’s proved oil and natural gas reserves, estimated cash flows from these reserves, and the Company’s commodity hedge positions. Upon a redetermination of the borrowing base, if actual borrowings exceed the revised borrowing capacity, CRP could be required to immediately repay a portion of its debt outstanding under the credit agreement. Borrowings under CRP’s revolving credit facility are guaranteed by certain of its subsidiaries. In connection with the fall 2019 semi-annual borrowing base redetermination under our credit facility, the borrowing base was reaffirmed at $1.2 billion and the amount of elected commitments remained at $800.0 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, which ranged from 125 to 225 basis points as of ~~September 30, 2019,~~March 31, 2020, 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; or (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points, plus an applicable margin, which ranged from 25 to 125 basis points as of ~~September 30, 2019,~~March 31, 2020, depending on the percentage of the borrowing base utilized. CRP also pays a commitment fee of 37.5 to 50 basis points on unused amounts under its facility. The applicable margins for the LIBOR loans and base rate loans referenced above reflect interest rate reductions that became effective on April 26, 2019 and are applicable as long as CRP’s total leverage ratio (as described below) is less than or equal to 3.0 to 1.0. If CRP’s total leverage ratio exceeds 3.0 to 1.0 in the future, the original applicable margins under the credit agreement would revert to the range from 150 to 250 basis points for LIBOR loans and 50 to 150 basis points for base rate loans, in each case depending on the percentage of the borrowing base utilized. ~~The weighted-average borrowing rate on our credit agreement, exclusive of unutilized commitment fees and the letter of credit noted above, was~~ ~~3.9%~~ ~~per annum for the nine months ended~~ ~~September 30, 2019~~.

CRP’s credit agreement contains restrictive covenants that limit its ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make or declare dividends; (v) enter into commodity hedges exceeding a specified percentage of the Company’s expected production; (vi) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (vii) incur liens; (viii) sell assets; and (ix) engage in transactions with affiliates.

~~Table of Contents~~

~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

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

Table of Contents

CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

compliance with the covenants and the financial ratios described above as of ~~September 30, 2019~~March 31, 2020 and through the filing of this Quarterly Report.

Senior Unsecured Notes

On March 15, 2019, CRP issued $500.0 million of 6.875% senior notes due 2027 (the “2027 Senior Notes”) in a 144A private placement at a price equal to 99.235% of par that resulted in net proceeds to CRP of $489.0 million, after deducting the original issuance discount of $3.8 million and debt issuance costs of $7.2 million. Interest is payable on the 2027 Senior Notes semi-annually in arrears on each April 1 and October 1, commencing October 1, 2019.

On November 30, 2017, CRP issued at par $400.0 million of 5.375% senior notes due 2026 (the “2026 Senior Notes” and collectively with the 2027 Senior Notes, the “Senior Notes”) in a 144A private placement that resulted in net proceeds to CRP of $391.0 million, after deducting $9.0 million in debt issuance costs. Interest is payable on the 2026 Senior Notes semi-annually in arrears on each January 15 and July 15, which commenced on July 15, 2018.

The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of CRP’s current subsidiaries that guarantee CRP’s revolving credit facility. The Senior Notes are not guaranteed by the Company, nor is the Company subject to the terms of the indentures governing the Senior Notes.

At any time prior to January 15, 2021 (for the 2026 Senior Notes) and April 1, 2022 (for the 2027 Senior Notes), the “Optional Redemption Dates,” CRP may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of either series of Senior Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 105.375% (for the 2026 Senior Notes) and 106.875% (for the 2027 Senior Notes) of the principal amount of the Senior Notes of the applicable series redeemed, plus any accrued and unpaid interest to the date of redemption; provided that at least 65% of the aggregate principal amount of each such series of Senior Notes remains outstanding immediately after such redemption, and the redemption occurs within 180 days of the closing date of such equity offering.

At any time prior to the Optional Redemption Dates, CRP may, on any one or more occasions, redeem all or a part of the Senior Notes at a redemption price equal to 100% of the principal amount of the Senior Notes redeemed, plus a “make-whole” premium, and any accrued and unpaid interest as of the date of redemption. On and after the Optional Redemption Dates, CRP may redeem the Senior Notes, in whole or in part, at redemption prices expressed as percentages of principal amount plus accrued and unpaid interest to the redemption date.

If CRP experiences certain defined changes of control (and, in some cases, followed by a ratings decline), each holder of the Senior Notes may require CRP to repurchase all or a portion of its Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes, plus any accrued but unpaid interest to the date of repurchase.

The indentures governing the Senior Notes contain covenants that, among other things and subject to certain exceptions and qualifications, limit CRP’s ability and the ability of CRP’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with these covenants as of ~~September 30, 2019~~March 31, 2020 and through the filing of this Quarterly Report.

Upon an Event of Default (as defined in the indentures governing the Senior Notes), the trustee or the holders of at least 25% of the aggregate principal amount of then outstanding Senior Notes may declare the Senior Notes immediately due and payable. In addition, a default resulting from certain events of bankruptcy or insolvency with respect to CRP, any restricted subsidiary of CRP that is a significant subsidiary, or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary, will automatically cause all outstanding Senior Notes to become due and payable.

On April 22, 2020, the Company commenced exchange offers to all eligible holders of its Senior Notes. Refer to Note 14—Subsequent Events for additional information on the Senior Notes exchanges.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 4—5—Asset Retirement Obligations

The following table summarizes the changes in the Company’s asset retirement obligations (“ARO”) associated with ~~our~~its working interests in oil and gas properties for the ~~nine~~three months ended ~~September 30, 2019:~~March 31, 2020:

(in thousands)
Asset retirement obligations as of January 1, 2019 $ 13,895
Liabilities acquired 101
Liabilities incurred 1,075
Liabilities divested and settled (1,112 )
Accretion expense 670
Asset retirement obligations as of September 30, 2019 $ 14,629



(in thousands)
Asset retirement obligations, beginning of period	$	16,874
Liabilities incurred and acquired	560
Liabilities divested and settled	(35		)
Accretion expense	252
Asset retirement obligations, end of period	$	17,651

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 plug and abandonment settlement amounts, inflation factors, credit adjusted discount rates and timing of settlement. To the extent future revisions to these assumptions impact the value of the existing ARO liability, a corresponding offsetting adjustment is made to the oil and gas property balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense.

Note 5—6—Stock-Based Compensation

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, 2019,~~March 31, 2020, the Company had ~~5,042,238~~4,196,761 shares of Class A Common Stock available for future grants. The LTIP provides for grants of restricted stock, stock options (including incentive stock options and nonqualified stock options), restricted stock units, stock appreciation rights ~~restricted stock, dividend equivalents, restricted stock units~~ and other stock or cash-based awards.

Stock-based compensation expense is recognized within both General and administrative expenses and Exploration expense in the Consolidated Statements of Operations. The Company accounts for forfeitures of awards granted under the LTIP as they occur in determining compensation expense.

The following table summarizes stock-based compensation expense recognized for the periods presented:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,				Three Months Ended March 31,
(in thousands)	2019		2018		2019		2018		2020		2019
Restricted stock awards	$	4,569	$	2,393	$	11,159	$	6,157	$	4,354	$	3,182
Stock option awards	2,557		2,337		7,766		6,853		984		2,584
Performance stock units	918		611		2,360		1,319		1,003		717
Other stock-based compensation expense⁽¹⁾	66		—		66		—		68		—
Total stock-based compensation expense	$	8,110	$	5,341	$	21,351	$	14,329	$	6,409	$	6,483


⁽¹⁾	Includes expenses related to the Company’s ~~Employees~~Employee Stock Purchase Plan (the “ESPP”). In May 2019, an aggregate of 2,000,000 shares were authorized by stockholders for issuance under the ESPP, which became effective on July 1, 2019. As of March 31, 2020, the Company had 1,940,801 shares of Class A Common Stock available for future issuance.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Restricted Stock

The following table provides information about restricted stock activity during the ~~nine~~three months ended ~~September 30, 2019:~~March 31, 2020:


	Awards		Weighted Average Grant Date Fair Value		Awards		Weighted Average Grant-Date Fair Value
Unvested balance as of December 31, 2018	1,535,945		$	17.88
Unvested balance as of December 31, 2019					4,838,996		$	8.51
Granted	3,906,196		6.70		1,305,473		2.76
Vested	(509,833	)	17.82		(245,909	)	15.47
Forfeited	(45,217	)	12.96		(405,535	)	5.69
Unvested balance as of September 30, 2019	4,887,091		8.99
Unvested balance as of March 31, 2020					5,493,025		7.04

The Company grants service-based restricted stock awards to executive officers and employees, which vest ratably over a three-year service period, and to directors, which vest over a one-year service period. Compensation cost for the service-based restricted stock awards is based on the closing market price of the Company’s Class A common stock on the grant date, and such costs are recognized ratably over the applicable vesting period. The weighted average grant-date fair value for restricted stock awards granted was ~~$6.70~~$2.76 and ~~$18.38~~$12.51 per share for the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ respectively. The total fair value of restricted stock awards that vested during the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~ was ~~$9.1~~$3.8 million and ~~$4.4~~$1.4 million, respectively. Unrecognized compensation cost related to restricted shares that were unvested as of ~~September 30, 2019~~March 31, 2020 was ~~$36.6~~$29.0 million, which the Company expects to recognize over a weighted average period of ~~2.4~~2.1 years.

Stock Options

Stock options that have been granted under the LTIP expire ten years from the grant date and vest ratably over a three-year service period. The exercise price for an option granted under the LTIP is the closing market price of the Company’s Class A Common Stock ~~as reported~~ on the ~~NASDAQ on the date of grant.~~grant date.

Compensation cost for stock options is based on the grant-date fair value of the award which is then recognized ratably over the vesting period of three years. The Company estimates the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the weighted average asset volatility of the Company and an identified set of comparable companies. Expected term is based on the simplified method and is estimated as the mid-point between the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.

The following table summarizes the assumptions and related information used to determine the grant-date fair value of stock options awarded during the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:


	For the Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2020			2019
Weighted average grant date fair value per share	$	4.47		$	7.74
Weighted average grant-date fair value per share							$	2.37		$	5.22
Expected term (in years)	6			6			6			6
Expected stock volatility	46		%	41		%	52		%	45		%
Dividend yield	—		%	—		%	—		%	—		%
Risk-free interest rate	2.3		%	2.6		%	1.7		%	2.5		%

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(Unaudited)

The following table provides information about stock option awards outstanding during the ~~nine~~three months ended ~~September 30, 2019:~~March 31, 2020:


	Options		Weighted Average Exercise Price		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in thousands)		Options		Weighted Average Exercise Price		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding as of December 31, 2018	4,559,334		$	16.55
Outstanding as of December 31, 2019								4,764,167		$	15.99
Granted	326,000		9.56					52,500		4.69
Exercised	—		—					—		—
Forfeited	(65,336	)	16.90					(22,502	)	18.74
Expired	(15,998	)	17.88					(42,666	)	18.99
Outstanding as of September 30, 2019	4,804,000		16.07		7.5	$	—
Exercisable as of September 30, 2019	2,654,623		16.14		7.2	$	—
Outstanding as of March 31, 2020								4,751,499		15.82		4.3	$	—
Exercisable as of March 31, 2020								3,987,631		16.15		3.5	$	—

The total fair value of stock options that vested during the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~ was ~~$4.4~~$3.5 million and ~~$3.7~~$3.4 million, respectively. ~~The intrinsic value of stock options exercised was approximately $0.2 million for the nine months ended September 30, 2018 and there~~There were 0 stock options exercised ~~for~~during either the ~~nine~~three months ended ~~September 30,~~March 31, 2020 or 2019. As of ~~September 30, 2019,~~March 31, 2020, there was ~~$6.2~~$3.1 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~~weighted-average period of ~~1.5~~1.6 years.

Performance Stock Units

~~The Company grants~~During the three months ended March 31, 2020 and 2019, there was no significant performance stock units to certain executive officers that are subject to market-based vesting criteria as well as a three-year service period. Vesting at the end of the three-year service period is subject to the condition that the Company’s stock price increases by a greater percentage, or decreases by a lesser percentage, than the average percentage increase or decrease, respectively, of the stock prices of a peer group of companies. The market-based conditions must be met in order for the stock awards to vest, and it is, therefore, possible that no shares could vest. However, the Company recognizes compensation expense for the performance stock units subject to market conditions regardless of whether it becomes probable that these conditions will be achieved or not and compensation expense is not reversed if vesting does not actually occur.

The grant-date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of our common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period.

The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the nine months ended September 30, 2019 and 2018:

For the Nine Months Ended September 30,
2019 2018
Weighted average grant-date fair value per share $ 6.68
$ 22.35
Number of simulations 1,000,000
1,000,000
Expected stock volatility 52.3 % 40.2 %
Dividend yield — % — %
Risk-free interest rate 1.8 % 2.8 %

~~The following table provides information about performance stock units outstanding during the nine months ended September 30, 2019:~~

Awards Weighted Average Grant Date Fair Value
Unvested balance as of December 31, 2018 386,459
$ 21.94
Granted 486,213
6.68
Vested —
—
Forfeited —
—
Unvested balance as of September 30, 2019 872,672
13.44

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

activity. As of ~~September 30, 2019,~~March 31, 2020, there was ~~$6.7~~$4.7 million of unrecognized compensation cost related to performance stock units that were unvested, which the Company expects to recognize on a pro-rata basis over a weighted average period of ~~2.0~~1.7 years.

Note 6—7—Derivative Instruments

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

Commodity Derivative Contracts

Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. The Company may periodically use 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 flows 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 may ~~opportunistically~~ use commodity derivative instruments known as fixed price swaps to realize a known price for a specific volume of production as well as basis swaps to hedge the difference between the index price and a local index price. All transactions are settled in cash with one party paying the other for the resulting difference in price multiplied by the contract volume.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of ~~September 30, 2019:~~March 31, 2020:

Period
Volume (Bbls)
Volume
(Bbls/d)

Weighted Average Differential ($/Bbl)⁽¹⁾
Crude oil basis swaps October 2019 - December 2019
920,000

10,000

$ (4.24 )



	Period	Volume (Bbls)	Volume (Bbls/d)	Weighted Average Fixed Price ($/Bbl)⁽¹⁾
Crude oil swaps	April 2020 - June 2020	2,730,000	30,000	$	25.88
	July 2020 - September 2020	2,208,000	24,000	26.58

	Period	Volume (Bbls)	Volume (Bbls/d)	Weighted Average Differential ($/Bbl)⁽²⁾
Crude oil basis swaps	April 2020 - June 2020	273,000	3,000	$	0.67
	July 2020 - September 2020	276,000	3,000	0.67
	October 2020 - December 2020	276,000	3,000	0.67


⁽¹⁾	These crude oil swap transactions are settled based on the NYMEX WTI price as of the specified settlement date.


⁽²⁾	These oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable settlement period.

Period
Volume (MMBtu)
Volume (MMBtu/d)
Weighted Average Fixed Price ($/MMBtu)⁽¹⁾
Natural gas swaps - Henry Hub October 2019 - December 2019
2,760,000

30,000

$ 2.78
Natural gas swaps - West Texas WAHA October 2019 - December 2019
1,380,000

15,000

1.61

Period
Volume (MMBtu)
Volume (MMBtu/d)
Weighted Average Differential ($/MMBtu)⁽²⁾
Natural gas basis swaps October 2019 - December 2019
3,220,000

35,000

$ (1.31 )



	Period	Volume (MMBtu)	Volume (MMBtu/d)	Weighted Average Fixed Price ($/MMBtu)⁽¹⁾
Natural gas swaps	April 2020 - June 2020	2,730,000	30,000	$	2.03
	July 2020 - September 2020	2,760,000	30,000	2.03
	October 2020 - December 2020	930,000	10,109	2.03

	Period	Volume (MMBtu)	Volume (MMBtu/d)	Weighted Average Differential ($/MMBtu)⁽²⁾
Natural gas basis swaps	April 2020 - June 2020	2,730,000	30,000	$	(1.62	)
	July 2020 - September 2020	2,760,000	30,000	(1.62		)
	October 2020 - December 2020	930,000	10,109	(1.62		)


⁽¹⁾	These natural gas swap contracts are settled based on ~~either i) the~~ NYMEX Henry Hub price ~~or ii) the Inside FERC West Texas WAHA price of natural gas, as applicable,~~ as of the specified settlement date.


⁽²⁾	These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas during each applicable settlement period.

Derivative Instrument Reporting. The Company’s oil and natural gas derivative instruments have not been designated as hedges for accounting ~~purposes; therefore,~~purposes. Therefore, all gains and losses are recognized in the Company’s Consolidated Statements of Operations. All derivative instruments are recorded at fair value in the Consolidated Balance Sheets, other than derivative instruments that meet the “normal purchase normal sale” exclusion, and any fair value gains and losses are recognized in current period earnings.

The following table presents the impact of the Company’s derivative instruments in its Consolidated Statements of Operations for the periods presented:



	Three Months Ended March 31,
(in thousands)	2020			2019
Net gain (loss) on derivative instruments	$	(8,505	)	$	(5,871	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~The following table presents the impact of our derivative instruments in our Consolidated Statements of Operations for the periods presented:~~

For the Three Months Ended September 30, For the Nine Months Ended September 30,
(in thousands) 2019 2018 2019 2018
Net gain (loss) on derivative instruments $ 1,522
$ (9,571 ) $ (2,221 ) $ 14,969

Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives are included in the accompanying Consolidated Balance Sheets as derivative assets and liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master netting agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The ~~table~~tables below summarizes the fair value amounts and the classification in the Consolidated Balance Sheets of the Company’s derivative contracts outstanding at the respective balance dates, as well as the gross recognized derivative assets, liabilities and offset amounts:


	Balance Sheet Classification	Gross Fair Value Asset/Liability Amounts		Gross Amounts Offset⁽¹⁾			Net Recognized Fair Value Assets/Liabilities		Balance Sheet Classification	Gross Fair Value Asset/Liability Amounts		Gross Amounts Offset⁽¹⁾			Net Recognized Fair Value Assets/Liabilities
(in thousands)		September 30, 2019								March 31, 2020
Derivative Assets
Commodity contracts	Current assets - Derivative instruments	$	1,402	$	(1,402	)	$	—	Current assets - Derivative instruments	$	8,589	$	(8,589	)	$	—
Derivative Liabilities
Commodity contracts	Current liabilities - Derivative instruments	5,835		(1,402		)	4,433		Current liabilities - Derivative instruments	17,366		(8,589		)	8,777

		December 31, 2018								December 31, 2019
Derivative Assets
Commodity contracts	Current assets - Derivative instruments	$	7,708	$	(6,076	)	$	1,632
Derivative Liabilities
Commodity contracts	Current liabilities - Derivative instruments	12,127		(6,076		)	6,051		Current liabilities - Derivative instruments	$	325	$	—		$	325


⁽¹⁾	The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets ~~and~~against derivative liabilities at settlement or in the event of a default under the agreements or contract termination.

Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are lenders under CRP’s credit agreement. The Company uses only credit agreement participants to hedge with, since these institutions are secured equally with the holders of any CRP bank debt, which eliminates the potential need to post collateral when Centennial is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 7—8—Fair Value Measurements

Recurring Fair Value Measurements

The Company follows ~~FASB ASC~~the Financial Accounting Standards Board’s Accounting Standard Codification (“ASC”) Topic 820, Fair Value Measurement and Disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

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

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

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

The following table presents, for each applicable level within the fair value hierarchy, ~~our~~the Company’s net derivative assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis:

(in thousands) Level 1 Level 2 Level 3
September 30, 2019
Total assets $ —
$ —
$ —
Total liabilities —
4,433
—
December 31, 2018
Total assets $ —
$ 1,632
$ —
Total liabilities —
6,051
—



(in thousands)	Level 1		Level 2		Level 3
March 31, 2020
Total assets	$	—	$	—	$	—
Total liabilities	—		8,777		—
December 31, 2019
Total assets	$	—	$	—	$	—
Total liabilities	—		325		—

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~~judgment 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 its 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. Refer to Note 6—7—Derivative Instruments for details of the gross and net derivatives assets, liabilities and offset amounts presented in the Consolidated Balance Sheets.

Nonrecurring Fair Value Measurements

The Company applies the provisions of the fair value ~~measurements of assets acquired and liabilities assumed are measured~~measurement standard on a nonrecurring basis to its non-financial assets and liabilities, including proved oil and gas properties. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances.

Impairment of Oil and Natural Gas Properties. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that the ~~acquisition date~~fair value of these assets may be below their carrying value. The significant decrease in the forward price curves for crude oil and natural gas in March of 2020 resulted in a triggering event which required the Company to reassess its proved oil and natural gas properties for impairment as of March 31, 2020. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows from oil and gas properties is less than the carrying amount of the assets. In this circumstance, the Company then recognizes impairment expense for the amount by which the carrying amount of proved properties exceeds their estimated fair value. The Company reviews its oil and natural gas properties on a field-by-field basis.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Company calculates the estimated fair values of its oil and natural gas properties using an income ~~valuation technique~~approach that is based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the ~~valuation~~expected future net cash flows used for the impairment review and the related fair value measurement of ~~acquired~~ oil and natural gas proved properties include estimates of: (i) reserves; (ii) future production decline rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; ~~(v) future cash flows;~~ and ~~(vi)~~(v) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management and all available information was considered at the ~~time~~date of the ~~valuation.~~review.

The impairment test performed by the Company indicated that a proved property impairment had occurred with respect to certain of its oil and gas fields, and therefore a non-cash impairment charge to reduce the carrying value of the impaired property to its fair value was recorded. Proved oil and natural gas properties with a previous carrying value of $771.4 million were partially written down to their fair value of $179.6 million, resulting in a non-cash impairment charge of $591.8 million being recorded during the three months ended March 31, 2020. The Company performed an impairment assessment of all its proved oil and gas properties as of March 31, 2020. Two of the Company’s fields were subject to an impairment write-down as quantified above, but the remaining five fields were not impaired due to their undiscounted cash flows exceeding their carrying values by 30% to over 100%. The Company did not recognize any impairment write-downs with respect to its proved property during the comparable 2019 period. Impairment expense for proved properties is presented as part of Impairment and Abandonment Expense in the Consolidated Statements of Operations.

Asset Retirement Obligations. The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO include ~~plugging~~the estimated future costs to plug and abandon oil and gas properties and reserve lives. Refer to Note 4—5—Asset Retirement Obligationsfor additional information on the Company’s ARO.

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

Other Financial Instruments

The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate their fair values because of the short-term maturities and/or liquid nature of these assets and liabilities.

The Company’s Senior Notes and borrowings under its credit agreement are recorded at cost. The following table summarizes the fair values and carrying values of these instruments as of ~~September 30, 2019 and December 31, 2018:~~the dates indicated:


	September 30, 2019				December 31, 2018				March 31, 2020				December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair value		Carrying Value		Fair Value		Carrying Value		Fair value
Credit facility due 2023⁽¹⁾	$	120,000	$	120,000	$	300,000	$	300,000	$	235,000	$	235,000	$	175,000	$	175,000
5.375% Senior Notes due 2026⁽²⁾	392,369		382,480		391,630		372,000		392,881		96,000		392,623		394,480
6.875% Senior Notes due 2027⁽²⁾	489,498		498,750						490,038		122,500		489,766		520,000


⁽¹⁾	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.


⁽²⁾	The Senior Notes’ carrying values include associated unamortized debt issuance costs and any discounts. The Senior Notes’ fair values were determined using quoted market prices for these debt securities, a Level 1 classification in the fair value hierarchy.

~~Note 8—Noncontrolling Interest~~

The noncontrolling interest relates to CRP Common Units that were originally issued to the Centennial Contributors in connection with the Business Combination and continue to be held by holders other than the Company. At the date of the Business Combination, the noncontrolling interest represented 10.9% of the ownership in CRP. The noncontrolling interest percentage is affected by various equity transactions such as CRP Common Unit and Class C Common Stock exchanges and Class A Common Stock activities.

As of September 30, 2019, the noncontrolling interest ownership of CRP decreased to 0.4% from 4.3% as of December 31, 2018. The decrease was mainly the result of the exchange by the Centennial Contributors and their affiliates on September 17, 2019 of 10,860,144 of their CRP Common Units (and corresponding shares of Class C Common Stock) for Class A Common Stock. A tax loss of $17.2 million was recorded in equity as a result of the conversion of shares from the noncontrolling interest owner. No cash proceeds were received by the Company in connection with this exchange.

The Company consolidates the financial position, results of operations and cash flows of CRP and reflects that portion retained by other holders of CRP Common Units as a noncontrolling interest. Refer to the Consolidated Statements of Shareholders’ Equity for a summary of the activity attributable to the noncontrolling interest during the period.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 9—Earnings Per Share

Basic earnings per share (“EPS”) is calculated by dividing net income available to Class A Common Stock by the weighted average shares of Class A Common Stock outstanding during each period. Diluted EPS is calculated by dividing adjusted net income available to Class A Common Stock by the weighted average shares of diluted Class A Common Stock outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted EPS calculation consists of (i) unvested restricted stock and performance stock units, outstanding stock options, withholding amounts from employee stock purchase plan 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. When a loss from continuing operations exists, all dilutive securities and potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.

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 shares outstanding for the period:


	For the Three Months Ended September 30,					For the Nine Months Ended September 30,				Three Months Ended March 31,
(in thousands, except per share data)	2019			2018		2019		2018		2020			2019
Net income (loss) attributable to Class A Common Stock	$	(3,585	)	$	39,288	$	6,180	$	168,919	$	(547,983	)	$	(8,112	)
Add: Income from conversion of Class C Common Stock	—			1,717		—		—
Adjusted net income (loss) attributable to Class A Common Stock	$	(3,585	)	$	41,005	$	6,180	$	168,919

Basic weighted average shares of Class A Common Stock outstanding										275,952			264,365
Diluted weighted average shares of Class A Common Stock outstanding										275,952			264,365

Basic net earnings (loss) per share of Class A Common Stock	$	(0.01	)	$	0.15	$	0.02	$	0.64	$	(1.99	)	$	(0.03	)
Diluted net earnings (loss) per share of Class A Common Stock	$	(0.01	)	$	0.15	$	0.02	$	0.63	$	(1.99	)	$	(0.03	)

Basic weighted average shares of Class A Common Stock outstanding	266,205			263,959		265,025		263,029
Add: Dilutive effect of potential common shares	—			3,766		60		3,625
Add: Dilutive effects of conversion of Class C Common Stock	—			12,189		—		—
Diluted weighted average shares of Class A Common Stock outstanding	266,205			279,914		265,085		266,654

The Company recognized a net loss during the three months ended March 31, 2020 and 2019. As a result, all potential common shares were anti-dilutive and were excluded from the calculation of diluted net earnings per share. The following table presents shares excluded from the diluted earnings per share calculation ~~as their impacts were anti-dilutive~~ for the periods ~~indicated:~~presented as their impact was anti-dilutive:


	For the Three Months Ended September 30,		For the Nine Months Ended September 30,		Three Months Ended March 31,
(in thousands)	2019⁽¹⁾	2018	2019	2018	2020	2019
Out-of-the-money stock options	4,817	142	4,680	318	4,782	4,556
Restricted stock					5,143	1,516
Employee Stock Purchase Plan					1,138	—
Weighted average shares of Class C Common Stock					1,034	12,003
Warrants	8,000	—	8,000	—	8,000	8,000
Restricted stock	3,827	—	2,313	—
Weighted average shares of Class C Common Stock	10,351	—	11,446	13,056
Performance stock units	—	—	—	52
Employee Stock Purchase Plan	8		—


⁽¹⁾	The Company recognized a net loss during the three months ended September 30, 2019. As a result, all potential common shares were anti-dilutive and excluded from the calculation of diluted net earnings per share.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 10—Transactions with Related Parties

Riverstone and its affiliates beneficially own more than 10% equity interest in the Company and are therefore considered related parties. The Company has a marketing agreement with Lucid Energy Delaware, LLC (“Lucid”), an affiliate of Riverstone. The Company believes that the terms of the marketing agreement with Lucid are no less favorable to either party than those held with unaffiliated parties. The following table summarizes the revenues recognized and the associated processing fees incurred from this marketing agreement as presented in the Consolidated Statements of Operations for the periods indicated as well as the related net receivables outstanding as of the balance sheet dates:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,				Three Months Ended March 31,
(in thousands)	2019		2018		2019		2018		2020		2019
Oil and gas sales	$	715	$	1,300	$	2,511	$	1,745	$	1,088	$	607
Gathering, processing and transportation expenses	793		183		1,719		273		953		317


(in thousands)	September 30, 2019		December 31, 2018		March 31, 2020		December 31, 2019
Accounts receivable, net⁽¹⁾	$	192	$	325	$	70	$	91

⁽¹⁾~~The receivables~~This accounts receivable represents amounts due from Lucid and are presented net of unpaid processing fees ~~incurred~~due Lucid as of the indicated period end date.

Note 11—Commitments and Contingencies

Commitments

The Company routinely enters into or extends operating agreements ~~office and equipment leases, drilling and completion rig contracts, among others,~~ in the ordinary course of business. During the three months ended March 31, 2020, the Company amended one of its firm crude oil sales agreements, which moved the start date of its physical delivery commitments of 30,000 Bbls/d from 2020 to January 1, 2021, and affirmed May 31, 2025 as the end of the initial term of the agreement. There has been no other material, non-routine changes in commitments during the ~~nine~~three months ended ~~September 30, 2019.~~March 31, 2020. Please refer to Note ~~14—~~13—Commitments and Contingencies included in Part II, Item 8 in the Company’s ~~2018~~2019 Annual Report.

Contingencies

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

Note 12—Revenues

Revenue from Contracts with Customers

Crude oil, natural gas and NGL sales are recognized at the point that control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials. As a result, the Company’s realized price of oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies both globally (in the case of crude oil) and locally.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Oil and gas revenues presented within the Consolidated Statements of Operations relate to the sale of oil, natural gas and NGLs as shown below:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,				Three Months Ended March 31,
	2019		2018		2019		2018		2020		2019
Operating revenues (in thousands):
Oil sales	$	200,196	$	184,510	$	590,055	$	533,507	$	170,505	$	175,554
Natural gas sales	11,070		14,311		31,655		46,612		8,358		12,497
NGL sales	17,864		36,059		66,228		88,422		13,906		26,518
Oil and gas sales	$	229,130	$	234,880	$	687,938	$	668,541	$	192,769	$	214,569

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

Oil sales

The Company’s crude oil sales contracts are generally structured whereby oil is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes title of the product. This delivery point is usually at the wellhead or at the inlet of a transportation pipeline. Revenue is recognized when control transfers to the purchaser at the delivery point based on the net price received from the purchaser. Any downstream transportation costs incurred by crude purchasers are reflected as a net reduction to oil sales revenues.

Natural gas and NGL sales

Under the Company’s natural gas processing contracts, liquids rich natural gas is delivered to a midstream processing entity at the inlet of the gas plant processing system. The midstream processing entity gathers and processes the raw gas and then remits proceeds to Centennial for the resulting sales of NGLs, while the Company generally elects to take its residue gas product “in-kind” at the plant tailgate. For these contracts, the Company evaluates when control is transferred and revenue should be recognized. Where the Company has concluded that control transfers at the tailgate of the processing facility, fees incurred prior to transfer of control are presented as gathering, processing and transportation expenses (“GP&T”) within the Consolidated Statements of Operations. Any transportation and fractionation costs incurred subsequent to the point of transfer of control are reflected as a net reduction to natural gas and NGL sales revenues presented in the table above.

Performance obligations

For all commodity products, the Company records revenue in the month production is delivered to the purchaser. Settlement statements for natural gas and NGL sales may not be received for 30 to 90 days after the date production volumes are delivered and for crude oil, generally within 30 days after delivery has occurred. However, payment is unconditional once the performance obligations have been satisfied. At this time, the volume and price can be reasonably estimated and amounts due from customers are accrued in Accounts ~~Receivable,~~receivable, net in the Consolidated Balance Sheets. As of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, such receivable balances were ~~$71.7~~$36.1 million and ~~$67.0~~$76.6 million, respectively.

The Company records any differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Historically, any identified differences between revenue estimates and actual revenue received have not been significant. For ~~both~~ the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods were not material.

Transaction price allocated to remaining performance obligations

For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC Topic 606,Revenue from contracts with Customers, which states the Company is not required to disclose the transaction price allocated to the remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, monthly sales of a product generally represent a separate performance obligation; therefore, future commodity volumes to be delivered and sold are wholly unsatisfied, and disclosure of the transaction price allocated to such unsatisfied performance obligations is not required.

Note 13—Leases

At contract inception, the Company determines whether or not an arrangement contains a lease. However, in connection with the implementation of ASC Topic 842,Leases (“ASC 842”), this assessment was made as of the adoption ~~date.~~date of ASC 842. Upon determination of a lease, a lease right-of-use (ROU) asset and related liability are recorded based on the present value of the future lease payments over the lease term. ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make future lease payments arising from the lease.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Currently, the Company has operating leases for drilling rig contracts, office rental agreements, and other wellhead equipment. As of ~~September 30, 2019,~~March 31, 2020, these leases have remaining lease terms ranging from two months to ~~three~~two years, some of which include options to extend the lease term for up to five years, and some of which include options to early terminate. These options are considered in determining the lease term and are included in the present value of future payments that are recorded for leases when the Company is reasonably certain to exercise the option. Leases with an initial term of one year or less are not recorded in the Consolidated Balance Sheets. Additionally, none of the Company’s lease agreements contain any material residual value guarantees or material restrictive covenants.

~~Table of Contents~~

~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

The present value of future lease payments is determined at the lease commencement date based upon the Company’s incremental borrowing rate. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for the Company’s specific ~~risk.~~risk and the specific lease term. The table below summarizes ~~our~~the Company’s weighted-average discount rate and weighted-average remaining lease term as of the period presented.



	As of ~~September 30, 2019~~March 31, 2020
Weighted-average discount rate	~~4.67~~4.82	%
Weighted-average remaining lease term (years)	1.26

The Company’s drilling rig contracts, office rental agreements, and wellhead equipment agreements contain both lease and non-lease components, which are combined and accounted for as a single lease component.

Variable lease payments are recognized in the period in which they are ~~incurred.~~incurred and include operating expenses related to the office rental agreements and expenses incurred on the drilling rig contracts in excess of the contractual rate. Expenses related to short-term leases are recognized on a straight-line basis over the lease term. The following table presents the various components of the Company’s lease expenses for the periods presented.


					Three Months Ended March 31,
(in thousands)	For the Three Months Ended September 30, 2019		For the Nine Months Ended September 30, 2019		2020		2019
Lease costs⁽¹⁾
Operating lease cost	$	9,361	$	30,754	$	4,676	$	10,587
Variable lease cost	1,819		3,323		1,352		801
Short-term lease cost	18,679		47,587
Total Lease Cost	$	29,859	$	81,664
Short-term lease cost⁽²⁾					19,610		12,224
Total lease cost					$	25,638	$	23,612

⁽¹⁾

The majority of the Company’s operating leases relate to the operations, drilling or completion of the Company’s wells. Therefore, the lease costs presented in the above table represent the total gross costs the Company incurs, which are not comparable to the Company’s net costs recorded to the Consolidated Statements of Operations, Consolidated Statements of Cash Flows or capitalized in the Consolidated Balance Sheets, as amounts therein are reflected net of amounts billed to the Company’s working interest partners.


⁽²⁾	Includes drilling rig lease costs of $11.2 million which may not necessarily be recurring in these amounts in the near-term based on the Company’s current drilling plan discussed in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Operational Highlights.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Maturities of the Company’s long-term operating lease liabilities by fiscal year as of ~~September 30, 2019~~March 31, 2020 are as follows:


(in thousands)	Total			Total⁽²⁾
2019⁽¹⁾⁽²⁾	$	6,428
2020	8,713
2020⁽¹⁾				$	5,847
2021	2,855			3,033
2022	425			425
Total lease payments	18,421			9,305
Less: imputed interest	(408		)	(313		)
Present value of lease liabilities ⁽³⁾	$	18,013		$	8,992


⁽¹⁾	Excludes payments made during the ~~nine~~three months ended ~~September 30, 2019.~~March 31, 2020.


⁽²⁾	~~Includes drilling rigs as~~Total lease payments exclude variable lease payments which can be charged under the terms of ~~September 30, 2019 with an initial term greater than one year.~~the lease agreements.


⁽³⁾	Of the total present value of lease liabilities, ~~$14.2~~$6.4 million was recorded to current Operating lease liabilities and ~~$3.9~~$2.6 million was recorded in noncurrent Operating lease liabilities in the Consolidated Balance Sheets as of ~~September 30, 2019.~~March 31, 2020.

Note 14—Subsequent Events

Nasdaq listing Notice

On April 21, 2020, the Company received written notification (the “Notice”) from the Listing Qualifications Department of the Nasdaq Stock Market LLC (“Nasdaq”) indicating that, for the last thirty consecutive business days, the bid price for the Company’s Class A Common Stock had closed below the minimum $1.00 per share requirement for continued listing on the Nasdaq Capital Market under Nasdaq Listing Rule 5550(a)(2) (the “Minimum Bid Requirement”). The ~~following is a schedule~~Notice has no immediate effect on the listing or trading of the Company’s ~~future contractual payments~~common stock on the Nasdaq Capital Market. The Company was provided an initial period of 180 calendar days, or until October 19, 2020, to regain compliance. However, due to recent market turmoil, Nasdaq has filed a rule change which has the effect of extending the Company’s compliance period until December 28, 2020. If the Company does not regain compliance with the Minimum Bid Requirement by December 28, 2020, the Company may be eligible for ~~operating leases under~~an additional 180 calendar day compliance period. The Company intends to actively monitor the ~~scope~~closing bid price of ~~ASC 840~~its Common Stock and will evaluate available options to regain compliance with the Minimum Bid Requirement, as necessary.

Senior Notes Exchange

On April 22, 2020, the Company commenced offers to all eligible holders of its Senior Notes to exchange any and all of their Senior Notes held for up to $250.0 million aggregate principal amount of newly issued 8% Second Lien Senior Secured Notes due 2025 and up to $200.0 million aggregate principal amount of newly issued 8% Third Lien Senior Secured Notes due 2027 (the “Exchange Offers”). In accordance with the Exchange Offers, the eligible holders of the Senior Notes can early tender their holdings on or before May 5, 2020 or can normally tender on or before May 19, 2020. The transaction is currently expected to close on May 22, 2020, subject to customary closing conditions.

Amendments to the Credit Agreement

On May 1, 2020, the Company and CRP entered into amendments to CRP’s amended and restated credit agreement (the “Amendments”) with the lenders to its existing credit agreement. Pursuant to the Amendments, the borrowing base and elected commitments were reduced to $700.0 million. In addition, to the extent that ~~had initial contractual terms greater than one year as~~the Exchange Offers close, the Amendments introduce a minimum availability condition to borrowing at the lesser of ~~December 31, 2018~~:

(in thousands) Drilling Rigs Office Leases
2019 $ 43,036
$ 3,057
2020 4,124
2,830
2021 —
2,761
2022 —
404
Total lease payments $ 47,160
$ 9,052

$100.0 million and 25% of the aggregate principal amount of the new second and third lien senior secured notes outstanding from the Exchange Offers discussed above. If the minimum availability condition to borrowing were to be determined at its maximum level of $100.0 million, it would have the resulting effect of limiting the amount of borrowings that CRP could draw against its $700.0 million credit facility to $600.0 million. Among other things, the Amendments also suspended the total funded debt to EBITDAX ratio (as specified in the Company’s existing credit agreement) through year-end 2021, introduced a new financial covenant testing the ratio of first lien debt to EBITDAX, and permitted the issuance of new senior secured notes in connection with the Exchange Offers described above.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Amendment to 2016 LTIP

On April 29, 2020, the stockholders of the Company approved the amended and restated LTIP, which, among other things, increased the number of shares of Class A Common Stock authorized for issuance by 8,250,000 shares.

Class C Common Stock Conversion to Class A Common Stock

~~Note 14—Subsequent Events~~On April 2, 2020, the legacy owners of CRP exchanged all of their remaining 1,034,119 CRP Common Units (and corresponding shares of Class C Common Stock) for Class A Common Stock, and as a result, the Company currently owns all of the membership interests in CRP

~~Credit Facility Amendment~~

In. No cash proceeds were received by the Company in connection with ~~the fall 2019 semi-annual borrowing base redetermination under our credit facility, the borrowing base was reaffirmed at $1.2 billion and the amount of elected commitments remained at $800.0 million.~~

this exchange.

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

The following discussion and analysis of our financial condition and results of operation should be read in conjunction with the accompanying consolidated financial statements and related notes. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes, continued and future impacts of Coronavirus Disease 2019 (“COVID-19”) and other uncertainties, as well as those factors discussed above in “Cautionary Statement Regarding Forward-Looking Statements” and in this Quarterly Report and our ~~2018~~2019 Annual Report under the heading “Item 1A. Risk Factors,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

Centennial Resource Development, Inc. (“Centennial,” “we,” “us,” or “our”) is an independent oil and natural gas company focused on the development of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are primarily 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~~highest return on capital. Unless otherwise specified or the context otherwise requires, all references in these discussions to “Centennial,” “we,” “us,” or “our” are to Centennial Resource Development, Inc. and its consolidated subsidiary, Centennial Resource Production, LLC (“CRP”).

Market Conditions

The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. As a result, there has been a significant decline in commodity prices during the first quarter of 2020. Specifically, WTI spot prices for crude oil dropped to $20.09 per barrel on March 30, 2020 from a high of $63.27 per barrel on January 6, 2020.

The oil and natural gas industry is cyclical, and ~~commodity prices can be volatile. It~~it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile and fluctuate due to global supply and demand, inventory levels, the continued effects from COVID-19, other geopolitical events, weather conditions ~~geopolitical events~~ and other factors. For example, WTI spot prices for crude oil declined significantly to a low of $44.48 per barrel during the fourth quarter of 2018 but reached a high of $66.30 per barrel in the second quarter of 2019, while the average crude oil price remained below $60 per barrel during the first nine months of 2019.

The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of ~~2017:~~2018:


	2017								2018								2019						2018								2019								2020
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1
Crude oil (per Bbl)	$	51.82	$	48.32	$	48.17	$	55.31	$	62.91	$	68.07	$	69.50	$	58.81	$	54.90	$	59.81	$	56.45	$	62.91	$	68.07	$	69.50	$	58.81	$	54.90	$	59.81	$	56.45	$	56.94	$	46.19
Natural gas (per MMBtu)	$	3.06	$	3.14	$	2.95	$	2.91	$	3.08	$	2.85	$	2.93	$	3.77	$	2.88	$	2.51	$	2.33	$	3.08	$	2.85	$	2.93	$	3.77	$	2.88	$	2.51	$	2.33	$	2.34	$	1.88

A sustained drop in oil, natural gas and NGL prices, ~~may~~such as we are experiencing thus far in March and April of 2020, will not only decrease our revenues on a per unit basis but ~~may~~can also reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore potentially lower our oil, natural gas and NGL reserve quantities.

Lower commodity prices (including our realized differentials), such as those that we are continuing to observe thus far in the ~~future could~~second quarter of 2020 and in the futures curve, can also result in further impairments of our proved oil and natural gas properties or undeveloped acreage (such as the impairments discussed below under “Results of Operations”) and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity and/or ability to finance planned capital expenditures. Lower realized prices may also reduce the borrowing base under CRP’s credit agreement (such as the reduction discussed below under “Financing Highlights”), 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. Additionally, the lower price environment and its impact to our operations could impact our ability to comply with the covenants under our credit agreement and Senior Notes.

~~2019~~

COVID-19 Outbreak

The COVID-19 outbreak and its development into a pandemic in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, suppliers and the communities in which we operate. Our operational employees are currently still able to work on site. However, we have taken various precautionary measures with respect to such operational employees such as requiring them to verify they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site, quarantining any operational employees who have shown signs of COVID-19 (regardless of whether such employee has been confirmed to be infected) and imposing social distancing requirements on work sites, all in accordance with the guidelines released by the Center for Disease Control. In addition, the vast majority of our non-operational employees are now working remotely. We have not yet experienced any material operational disruptions (including disruptions from our suppliers and service providers) as a result of the COVID-19 outbreak, nor have we had any confirmed cases of COVID-19 on any of our work sites.

2020 Highlights and Future Considerations

The changes in the macro environment and related decline in commodity prices that occurred during the first quarter of 2020 discussed above have significantly impacted our results of operations for the three months ended March 31, 2020. However, the majority of these market impacts were experienced at the end of the first quarter of 2020. Therefore, we believe that our future operating results and near-term financial condition will continue to be impacted. Further, our results of operations for the three months ended March 31, 2020 discussed within this Quarterly Report will likely not be indicative of our operating results for the remainder of 2020 due to the timing of operational changes and continued volatility of commodity prices.

Operational Highlights

We operated ~~on average,~~ a ~~six-rig~~five-rig drilling program during the majority of the first ~~nine~~three months of ~~2019~~2020, which enabled us to complete and bring online 5722 gross operated ~~wells. The total number of completed~~ wells ~~during the first nine months of 2019 had~~with an average effective lateral length of approximately ~~7,600~~6,900 feet.

Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we have recently suspended all drilling and completion activities in order to preserve capital. Specifically, we recently reduced our operated drilling rig program to zero rigs in April of 2020. In addition, given the weakness in realized oil prices, we are actively evaluating whether to voluntarily curtail or shut-in a substantial portion of our current production volumes, and we expect to voluntarily curtail up to 40% of our production during the month of May. Further potential curtailment decisions will continue to be evaluated and made on a month-to-month basis subject to market conditions, storage or transportation constraints, and contractual obligations. As substantially all of our revenues are generated by the production and sale of hydrocarbons, the curtailment or shut-in of our production could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.

Divestiture Highlights

On February 24, 2020, we entered into a purchase and sale agreement to sell our water disposal assets for a base sale price of approximately $150.0 million in cash at closing with up to an additional $75.0 million in deferred incentive payments based on future drilling activity (all amounts are subject to post-closing adjustments). The water disposal assets include certain saltwater disposal wells and the associated water infrastructure located in Reeves and Ward counties in Texas. The original closing date of the sale was March 31, 2020, however, the transaction has been delayed. While the transaction currently remains pending, either party may terminate the transaction if closing does not occur on or before May 15, 2020.

Financing Highlights

On April 22, 2020, we commenced offers to all eligible holders of our 5.375% Senior Notes due 2026 (the “2026 Senior Notes”) and 6.875% Senior Notes due 2027 (“the 2027 Senior Notes” and together with the 2026 Senior Notes, the “Senior Notes”) to exchange (the “Exchange Offers”) any and all of their Senior Notes held for up to $250.0 million aggregate principal amount of newly issued 8% Second Lien Senior Secured Notes due 2025 (the “Second Lien Notes”) and up to $200.0 million aggregate principal amount of newly issued 8% Third Lien Senior Secured Notes due 2027 (together with the Second Lien Notes, the “New Notes”). In accordance with the Exchange Offers, the eligible holders of the Senior Notes can early tender their holdings on or before May 5, 2020 or can normally tender on or before May 19, 2020. The transaction is currently expected to close on May 22, 2020, subject to customary closing conditions.

On May 1, 2020, we entered into amendments to CRP’s amended and restated credit agreement (the “Amendments”) with the lenders to our existing credit agreement. Pursuant to the Amendments, the borrowing base and elected commitments were reduced to $700.0 million. In addition, to the extent that the Exchange Offers close, the Amendments introduce a minimum availability condition to borrowing at the lesser of $100.0 million and 25% of the aggregate principal amount of New Notes outstanding from the Exchange Offers. Among other things, the Amendments also suspended the total funded debt to EBITDAX ratio (as specified in the existing credit agreement) through year-end 2021, introduced a new financial covenant testing the ratio of first lien debt to EBITDAX, and permitted the issuance of new senior secured notes in connection with the ~~spring 2019 semi-annual borrowing base redetermination under our credit facility,~~Exchange Offers described above.

Marketing Highlights

We have entered into fixed price oil swaps for April through December of 2020 to protect against possible, additional near-term declines in oil prices. During this period, the ~~borrowing base under the revolving credit facility was increased from $1.0 billion to $1.2 billion, but the amount~~Company has hedged an average of ~~elected commitments remained~~approximately 19,400 barrels per day of oil at ~~$800.0 million.~~a weighted average price of $26.79 per barrel. In addition, ~~CRP~~we have natural gas hedges and ~~the lenders amended the credit agreement to reduce the applicable margin by 25~~oil basis ~~points~~swaps in place for the LIBOR loans to a range of 125 to 225 basis points and to reduce the applicable margin by 25 basis points for base rate loans to 25 to 125 basis points, in each case depending on the percentage of the borrowing base utilized. These reductions in the applicable margins became effective in April 2019 and remain applicable as long as CRP’s total leverage ratio is less than or equal to 3.0 to 1.0; otherwise, the original applicable margins would be applied.

In connection with the fall 2019 semi-annual borrowing base redetermination under our credit facility, the borrowing base was reaffirmed at $1.2 billion and the amount of elected commitments remained at $800.0 million.2020.

Results of Operations

Three Months Ended ~~September 30, 2019~~March 31, 2020 Compared to Three Months Ended ~~September 30, 2018~~March 31, 2019

The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes:


	For the Three Months Ended September 30,						Increase/(Decrease)					Three Months Ended March 31,						Increase/(Decrease)
	2019			2018			$			%		2020			2019			$			%
Net revenues (in thousands):
Oil sales	$	200,196		$	184,510		$	15,686		9	%	$	170,505		$	175,554		$	(5,049	)	(3	)%
Natural gas sales	11,070			14,311			(3,241		)	(23	)%	8,358			12,497			(4,139		)	(33	)%
NGL sales	17,864			36,059			(18,195		)	(50	)%	13,906			26,518			(12,612		)	(48	)%
Oil and gas sales	$	229,130		$	234,880		$	(5,750	)	(2	)%	$	192,769		$	214,569		$	(21,800	)	(10	)%

Average sales prices:
Oil (per Bbl)	$	51.71		$	55.68		$	(3.97	)	(7	)%	$	45.14		$	48.15		$	(3.01	)	(6	)%
Effect of derivative settlements on average price (per Bbl)	(3.00		)	2.56			(5.56		)	(217	)%	(0.01		)	(0.22		)	0.21			95	%
Oil net of hedging (per Bbl)	$	48.71		$	58.24		$	(9.53	)	(16	)%	$	45.13		$	47.93		$	(2.80	)	(6	)%

Average NYMEX price for oil (per Bbl)	$	56.45		$	69.50		$	(13.05	)	(19	)%	$	46.19		$	54.90		$	(8.71	)	(16	)%
Oil differential from NYMEX	(4.74		)	(13.82		)	9.08			66	%	(1.05		)	(6.75		)	5.70			84	%

Natural gas (per Mcf)	$	0.96		$	1.83		$	(0.87	)	(48	)%	$	0.78		$	1.39		$	(0.61	)	(44	)%
Effect of derivative settlements on average price (per Mcf)	0.30			0.05			0.25			500	%	—			0.05			(0.05		)	(100	)%
Natural gas net of hedging (per Mcf)	$	1.26		$	1.88		$	(0.62	)	(33	)%	$	0.78		$	1.44		$	(0.66	)	(46	)%

Average NYMEX price for natural gas (per Mcf)	$	2.33		$	2.93		$	(0.60	)	(20	)%	$	1.88		$	2.88		$	(1.00	)	(35	)%
Natural gas differential from NYMEX	(1.37		)	(1.10		)	(0.27		)	(25	)%	(1.10		)	(1.49		)	0.39			26	%

NGL (per Bbl)	$	14.47		$	30.85		$	(16.38	)	(53	)%	$	14.30		$	19.74		$	(5.44	)	(28	)%

Net production:
Oil (MBbls)	3,872			3,314			558			17	%	3,778			3,646			132			4	%
Natural gas (MMcf)	11,491			7,837			3,654			47	%	10,715			8,964			1,751			20	%
NGL (MBbls)	1,234			1,169			65			6	%	972			1,343			(371		)	(28	)%
Total (MBoe)⁽¹⁾	7,021			5,790			1,231			21	%	6,536			6,483			53			1	%

Average daily net production:
Oil (Bbls/d)	42,079			36,027			6,052			17	%	41,512			40,508			1,004			2	%
Natural gas (Mcf/d)	124,896			85,180			39,716			47	%	117,751			99,596			18,155			18	%
NGL (Bbls/d)	13,417			12,706			711			6	%	10,683			14,927			(4,244		)	(28	)%
Total (Boe/d)⁽¹⁾	76,312			62,930			13,382			21	%	71,820			72,035			(215		)	—	%


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

Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the three months ended ~~September 30, 2019~~March 31, 2020 were ~~$5.8~~$21.8 million (or 2%10%) lower than total net revenues for the three months ended ~~September 30, 2018.~~March 31, 2019. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

Average realized sales prices for oil, natural gas and NGLs decreased in the ~~third~~first quarter of ~~2019~~2020 compared to the same ~~2018~~2019 period. The average price for oil before the effects of hedging decreased 7%6%, the average price for natural gas before the effects of

hedging decreased ~~48%~~44%, and the average price for NGLs decreased ~~53%~~28% between periods. The 7%6% decrease in the average realized oil price was ~~mainly~~ the result of lower NYMEX crude prices between periods (average NYMEX prices decreased ~~19%~~16%), ~~which~~and this lower index price was partially offset by improved oil differentials (a decrease of ~~$9.08~~$5.70 per Bbl). The average realized sales price of natural gas decreased ~~48%~~44% due to lower average NYMEX gas prices between periods (average NYMEX prices decreased ~~20%) and wider~~$1.00), but this decrease was partially offset by improved gas differentials ~~(an increase~~(a decrease of ~~$0.27~~$0.39 per Mcf). between periods. The continued widening of natural gas price differentials was due to natural gas pipeline takeaway capacity constraints impacting the Permian Basin, which has in turn depressed natural gas prices in West Texas. A new gas pipeline was placed into service late in the third quarter of 2019 in the Permian Basin and continued construction of additional natural gas pipelines are planned through 2021. These third party pipelines are expected to provide relief from these wider natural gas differentials. The overall 53%28% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products in the ~~third~~first quarter ~~2019~~of 2020 as compared to the ~~third~~first quarter of ~~2018.~~2019. The market prices for oil, natural gas and NGLs were all impacted by the lower global demand for oil and gas as a result of COVID-19 as well as commodity supply disruptions, which resulted in significant price declines in March and April of 2020 as discussed in the market conditions section above.

The decreases in realized sales prices were partially offset by slightly higher net production volumes between periods. Net production volumes for oil and natural gas increased 4% and ~~NGLs increased 17%, 47% and 6%~~20%, respectively, while NGL production volumes decreased 28% between periods. The oil volume increase resulted primarily from our successful drilling activities in the Delaware Basin. Since the ~~third~~first quarter ~~2018,~~2019, we placed 7986 gross operated wells on production in the Delaware, ~~Basin,~~ which added ~~1,978~~1,864 MBbls of net oil production to the ~~third~~first quarter of ~~2019.~~2020. These oil volume increases were partially offset by normal field production declines across our existing wells. Natural gas and NGLs are produced concurrently with our crude oil volumes, ~~which~~ typically ~~results~~resulting in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. However, during the ~~third~~first quarter of ~~2019,~~2020, the main processor of our ~~wet~~raw gas ~~temporarily switched from~~operated in ethane-rejection as compared to operating in ethane-recovery ~~to ethane-rejection due to lower ethane prices in~~during the ~~Permian Basin. This~~same 2019 period. As a result of this switch, ~~yielded~~we recovered an increased amount of natural gas ~~recovered~~ from our wet gas stream ~~which resulted~~and recovered fewer NGLs, resulting in a significant increase in natural gas volumes between periods (up ~~47%~~20%) and a ~~much lower increase (6%)~~28% decrease in NGL volumes between periods. ~~Our gas processor’s switch to ethane-rejection may not necessarily be a reoccurring trend for the remainder of 2019 or for future periods.~~

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


	For the Three Months Ended September 30,				Increase/(Decrease)					Three Months Ended March 31,				Increase/(Decrease)
	2019		2018		$			%		2020		2019		$		%
Operating costs (in thousands):
Lease operating expenses	$	42,330	$	23,706	$	18,624		79	%	$	32,639	$	29,862	$	2,777	9	%
Severance and ad valorem taxes	12,213		14,410		(2,197		)	(15	)%	16,573		16,120		453		3	%
Gathering, processing and transportation expenses	20,853		16,090		4,763			30	%	16,939		15,024		1,915		13	%
Operating costs per Boe:
Lease operating expenses	$	6.03	$	4.09	$	1.94		47	%	$	4.99	$	4.61	$	0.38	8	%
Severance and ad valorem taxes	1.74		2.49		(0.75		)	(30	)%	2.54		2.49		0.05		2	%
Gathering, processing and transportation expenses	2.97		2.78		0.19			7	%	2.59		2.32		0.27		12	%

Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended ~~September 30, 2019~~March 31, 2020 increased ~~$18.6~~$2.8 million compared to the three months ended ~~September 30, 2018.~~March 31, 2019. Higher LOE for the ~~third~~first quarter of ~~2019~~2020 was primarily related to a ~~$14.9~~$5.6 million increase in expense associated with our higher well count. We had ~~319~~377 gross operated horizontal wells as of ~~September 30, 2019~~March 31, 2020 as compared to ~~240~~280 gross operated horizontal wells as of ~~September 30, 2018.~~March 31, 2019. The net increase in well count was mainly due to our drilling activity adding 7986 gross operated wells since the ~~third~~first quarter of ~~2018,~~2019, which was further adjusted for acquisitions and divestitures. ~~In addition,~~Such increase was partially offset by a $2.8 million decreased in workover expense ~~increased $3.7 million~~ between periods as a result of ~~our higher well count and related higher~~lower workover activity.

LOE on a per Boe basis increased when comparing the ~~third~~first quarter of ~~2019~~2020 to the same ~~2018~~2019 period. LOE per Boe was ~~$6.03~~$4.99 for the ~~third~~first quarter of ~~2019,~~2020, which represents an increase of ~~$1.94~~$0.38 per Boe from the ~~third~~first quarter of ~~2018.~~2019. This increase in rate was mainly due to the following factors: (i) a decline in the ratio of flush production to base production based on our level of D&C activity in ~~2019;~~2020; (ii) ~~higher monthly rental rates for electric submersible pumps (“ESPs”) and wellhead generators, (iii)~~ increased wellhead chemical ~~costs, (iv) increased number~~costs; and (iii) higher electricity expense in the first quarter of ~~field employees, resulting in higher~~2020 . These increases were partially offset by lower contract labor costs between periods and ~~(v) higher electricity rates incurred in~~ the ~~third quarter~~lower level of ~~2019 associated with extreme heat in West Texas and associated demand.~~workover activity discussed above.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended ~~September 30, 2019 decreased $2.2~~March 31, 2020 increased $0.5 million compared to the three months ended ~~September 30, 2018.~~March 31, 2019. Severance taxes are primarily based on the market value of production at the wellhead, while ad valorem taxes are generally based on the ~~valuation~~taxable value of ~~our~~ proved developed oil and natural gas reserves and vary across the different counties in which we operate. Severance and ad valorem taxes as a percentage of total net revenues ~~decreased~~increased to ~~5.3%~~8.6% for three months ended ~~September 30, 2019~~March 31, 2020 as compared to ~~6.1%~~7.5% for the same ~~2018 period. Severance taxes for three months ended September 30,~~ 2019 ~~were down $4.3 million compared to the third quarter of 2018 primarily~~period due to ~~$3.3 million in tax credits received in the 2019 period for wells that qualified for the “high-cost gas well”~~

~~exemption, whose criteria are defined by the Texas Railroad Commission. Such decreases in severance taxes were partially offset by~~ increased ad valorem taxes of ~~$2.1~~$1.1 million between periods, ~~as a result of~~resulting from our higher well count and higher oil and gas ~~property values.~~reserve values.

Severance and ad valorem taxes decreased on a per Boe basis to $1.74 for the third quarter of 2019 from $2.49 for the third quarter of 2018. This 30% decrease in rate is due to lower average realized sales prices for oil, natural gas and NGLs between periods, as well as “high cost gas” credits discussed above.

Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended ~~September 30, 2019~~March 31, 2020 increased ~~$4.8~~$1.9 million as compared to the three months ended ~~September 30, 2018~~March 31, 2019 primarily due to ~~higher natural gas and NGL volumes sold between periods, which~~a $2.8 million decrease in ~~turn resulted~~reimbursements (net of related fees) received from third parties for their usage of our firm transport (“FT”) capacity. This was partially offset by a decrease in ~~a higher amount of~~ plant processing costs, transportation tariffs and gathering fees ~~being incurred.~~incurred between periods.

On a per Boe basis, GP&T increased 7%12% from ~~$2.78~~$2.32 for the ~~third~~first quarter of ~~2018~~2019 to ~~$2.97~~$2.59 per Boe for the ~~third~~first quarter of ~~2019. However, these fees are mainly incurred on our volumes of natural gas and NGL processed, and the Boe rate on~~2020. On a natural gas and NGL ~~volume~~volumes basis (i.e. excluding crude oil barrels) ~~was $6.62~~the Boe rate likewise increased between periods to $6.14 from $5.29 for the three months ended ~~September 30,~~March 31, 2020 and 2019, respectively. These rate increases were mainly attributable to a decrease in reimbursements (net of related FT fees) received from third parties for their usage of our FT capacity as discussed above. This was partially offset by decreased plant processing costs, which ~~was consistent with our rate of $6.50 for the comparable 2018 period (2% higher).~~are primarily based on natural gas and NGL prices that were both lower between periods.

Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A”) for the periods indicated:


	For the Three Months Ended September 30,				Three Months Ended March 31,
(in thousands, except per Boe data)	2019		2018		2020		2019
Depreciation, depletion and amortization	$	112,720	$	83,423	$	101,258	$	96,558
Depreciation, depletion and amortization per Boe	$	16.06	$	14.41	$	15.49	$	14.89

Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved ~~reserves or~~developed and proved ~~developed~~undeveloped reserves. For the three months ended ~~September 30, 2019,~~March 31, 2020, DD&A expense amounted to ~~$112.7~~$101.3 million, an increase of ~~$29.3~~$4.7 million over the same ~~2018~~2019 period. The primary factor contributing to higher DD&A expense in ~~2019~~2020 was the increase in DD&A rates between periods, which added $3.9 million of incremental DD&A expense to the first quarter of 2020, while the increase in our overall production volumes between periods ~~which added $17.7 million of incremental DD&A expense to the third quarter of 2019, while higher DD&A rates between periods~~ contributed an additional ~~$11.6~~$0.8 million of DD&A expense to the ~~third~~first quarter of ~~2019.~~2020.

DD&A per Boe was ~~$16.06~~$15.49 for the ~~third~~first quarter of ~~2019~~2020 compared to ~~$14.41~~$14.89 for the same period in ~~2018.~~2019. The ~~primary factors contributing to this higher~~increase in the DD&A rate ~~were (i) revisions~~was due to ~~proved and proved developed reserves subsequent to the third quarter of 2018 and (ii)~~ a higher level of infrastructure costs ~~(having~~in the trailing twelve months, which have no associated proved reserve ~~adds).~~adds when they are incurred. However, our DD&A per Boe rate of $15.49 decreased from our fourth quarter DD&A rate of $16.75 due to proved developed and proved undeveloped reserves added during the first quarter of 2020 combined with lower drilling and completion costs per well that we realized during the three months ended March 31, 2020. In addition, we anticipate that our DD&A per Boe rate for the remainder of 2020 may continue to decline as a result of the proved property impairment recognized in the first quarter of 2020 as discussed below.

Impairment and Abandonment Expense.During the three months ended ~~September 30, 2019, $6.7~~March 31, 2020, $611.3 million of impairment and abandonment expense was incurred related to certain of our oil and natural gas properties. This expense consisted of (i) a $591.8 million non-cash impairment of our proved oil and gas properties as a result of depressed oil, natural gas and NGL commodity prices at March 31, 2020, and (ii) $19.5 million related to the amortization of ~~lease~~leasehold expiration costs associated with individually insignificant unproved properties. In

We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that the ~~third quarter~~fair value of ~~2018, $8.6~~these assets may be below their carrying value. Fair values of our oil and natural gas properties is estimated using an income approach that is based on the discounted expected future net cash flows from these assets. This valuation is based on inputs which require significant judgments and include estimates of: (i) reserves; (ii) future production decline rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; and (v) a market participant-based weighted average cost of capital rate.

We performed an impairment assessment of all our proved oil and gas properties as of March 31, 2020. Two of our fields were subject to impairment write-downs as quantified above, but the remaining five fields were not impaired due to their undiscounted cash flows exceeding their carrying values by 30% to over 100%. This impairment assessment was performed using commodity price futures curves as of March 31, 2020. If future oil, natural gas and NGL prices continue to decline to lower levels, or other estimates impacting future net cash flows deteriorate (e.g. reserves, price differentials, future operating and/or development costs), our proved oil and gas properties could be subject to additional impairment write-downs in future periods.

During the three months ended March 31, 2019, $31.3 million of impairment and abandonment expense was incurred ~~for~~related to undeveloped leasehold acreage. This expense consisted of (i) $14.7 million related to non-core acreage that expired during the period after efforts to extend, sell or trade these leases were ~~unsuccessful.~~unsuccessful, and (ii) $16.6 million for impaired acreage following an acreage sale initiated in the first quarter of 2019.

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


	For the Three Months Ended September 30,				Three Months Ended March 31,
(in thousands)	2019		2018		2020		2019
Geological and geophysical costs	$	2,116	$	2,259	$	1,993	$	1,634
Rig termination fees					1,499		283
Stock-based compensation	753		453		517		599
Exploration expense	$	2,869	$	2,712	$	4,009	$	2,516

Exploration expense was ~~$2.9~~$4.0 million for the three months ended ~~September 30, 2019 and was largely consistent with~~March 31, 2020 compared to $2.5 million for the ~~$2.7 million incurred during the same prior year period.~~three months ended March 31, 2019. Exploration expense mainly consists of topographical studies, geographical and geophysical (“G&G”) projects, and salaries and expenses of G&G ~~personnel.~~

personnel and includes other operating costs. The period over period increase was primarily related to the $1.2 million increase in rig termination fees incurred in the first quarter of 2020 as a result of reducing our operated drilling program from five rigs to one in March of 2020.

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


	For the Three Months Ended September 30,				Three Months Ended March 31,
(in thousands)	2019		2018		2020		2019
Cash general and administrative expenses	$	12,679	$	11,673	$	12,978	$	12,234
Stock-based compensation	7,357		4,888		5,892		5,884
General and administrative expenses	$	20,036	$	16,561	$	18,870	$	18,118

G&A expenses for the three months ended ~~September 30, 2019~~March 31, 2020 were ~~$20.0 million compared to $16.6 million for~~consistent with the ~~third~~same period of 2019. This was a result of consistent head count and activity during both periods. As a result of our reduction in force announced in the second quarter of ~~2018. Our~~2020, we will incur one-time non-reoccurring severance costs in the second quarter of 2020. Further, we anticipate that our cash G&A expenses ~~were higher~~will decline from the expense level incurred in ~~2019 primarily due to $2.5 million~~the first quarter of 2020, as a result of these reductions in ~~higher stock-based compensation and $0.6 million in increased software expenses.~~personnel.

Other Income and Expenses.

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


	For the Three Months Ended September 30,						Three Months Ended March 31,
(in thousands)	2019			2018			2020			2019
Credit facility	$	1,566		$	1,364		$	2,167		$	3,734
5.375% Senior Notes due 2026	5,375			5,375			5,374			5,374
6.875% Senior Notes due 2027	8,594			—			8,594			1,528
Amortization of debt issuance costs and debt discount	783			452			799			512
Interest capitalized	(1,072		)	(657		)	(513		)	(988		)
Total	$	15,246		$	6,534		$	16,421		$	10,160

Interest expense was ~~$8.7~~$6.3 million higher for the three months ended ~~September 30, 2019~~March 31, 2020 as compared to the three months ended ~~September 30, 2018~~March 31, 2019 primarily due to ~~interest that was incurred~~$7.1 million in ~~the third quarter of 2019~~increased interest on our 2027 Senior ~~Notes. These notes~~Notes due to the fact that they were issued in March of ~~2019; therefore, such~~2019. This increase was partially offset by lower interest ~~was not similarly~~expense incurred on the credit facility due to decreased borrowings outstanding coupled with lower interest rates in the ~~2018 period.~~first quarter of 2020. Our weighted average borrowings outstanding under our credit facility were $233.9 million versus $304.3 million for the three months ended March 31, 2020 and 2019, respectively. Our credit facility’s weighted average effective interest rate (which is a LIBOR-based rate) was 2.84% and 4.37% for the three months ended March 31, 2020 and 2019, respectively. LIBOR was lower in the first quarter of 2020 versus the prior year quarter.

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 the forward price curves for the underlying commodities and (ii) monthly cash settlements on our hedged derivative positions.

The following table presents gains and losses on our derivative instruments for the periods indicated:


	For the Three Months Ended September 30,						Three Months Ended March 31,
(in thousands)	2019			2018			2020			2019
Cash settlement gains (losses)	$	(8,218	)	$	8,866		$	(53	)	$	(377	)
Non-cash mark-to-market derivative gain (loss)	9,740			(18,437		)	(8,452		)	(5,494		)
Total	$	1,522		$	(9,571	)	$	(8,505	)	$	(5,871	)

Income Tax Expense. We recognized income tax ~~expense~~benefits of ~~$1.4~~$83.2 million and ~~$11.7~~$2.3 million for the three months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ respectively. The ~~decrease~~increase in income tax ~~expense~~benefit for the three months ended ~~September 30,~~March 31, 2020 as compared to 2019 was primarily due to ~~lower~~a larger pre-tax book ~~income~~loss of ~~$55.6~~$622.8 million from the third quarter of 2018 to the third quarter of 2019, which was partially offset by a $4.9 million discrete permanent item in the third quarter of 2019 that had the effect of increasing income tax expense for that period.

between periods. Our ~~provision~~provisions for income taxes for the ~~third~~first quarter of ~~2019~~2020 and ~~2018~~2019 differed from the ~~amount~~amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book ~~income because of~~loss primarily due to i) state income ~~taxes~~taxes; ii) estimated permanent differences; and ~~permanent differences.~~

~~Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018~~

~~The following table provides~~iii) the ~~components~~recognition of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes:

For the Nine Months Ended September 30, Increase/(Decrease)
2019 2018 $ %
Net revenues (in thousands):

Oil sales $ 590,055

$ 533,507
$ 56,548
11 %
Natural gas sales 31,655

46,612
(14,957 ) (32 )%
NGL sales 66,228

88,422
(22,194 ) (25 )%
Oil and gas sales $ 687,938

$ 668,541
$ 19,397
3 %

Average sales prices:

Oil (per Bbl) $ 51.58

$ 59.27
$ (7.69 ) (13 )%
Effect of derivative settlements on average price (per Bbl) (1.15 )
1.50
(2.65 ) (177 )%
Oil net of hedging (per Bbl) $ 50.43

$ 60.77
$ (10.34 ) (17 )%

Average NYMEX price for oil (per Bbl) $ 57.05

$ 66.75
$ (9.70 ) (15 )%
Oil differential from NYMEX (5.47 )
(7.48 ) 2.01
27 %

Natural gas (per Mcf) $ 1.04

$ 2.02
$ (0.98 ) (49 )%
Effect of derivative settlements on average price (per Mcf) 0.36

0.04
0.32
800 %
Natural gas net of hedging (per Mcf) $ 1.40

$ 2.06
$ (0.66 ) (32 )%

Average NYMEX price for natural gas (per Mcf) $ 2.57

$ 2.95
$ (0.38 ) (13 )%
Natural gas differential from NYMEX (1.53 )
(0.93 ) (0.60 ) (65 )%

NGL (per Bbl) $ 16.88

$ 29.08
$ (12.20 ) (42 )%

Net production:

Oil (MBbls) 11,440

9,002
2,438
27 %
Natural gas (MMcf) 30,409

23,092
7,317
32 %
NGLs (MBbls) 3,923

3,040
883
29 %
Total (MBoe)⁽¹⁾
20,431

15,891
4,540
29 %

Average daily net production:

Oil (Bbls/d) 41,903

32,973
8,930
27 %
Natural gas (Mcf/d) 111,388

84,585
26,803
32 %
NGLs (Bbls/d) 14,371

11,137
3,234
29 %
Total (Boe/d)⁽¹⁾
74,839

58,208
16,631
29 %


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

~~Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the nine months ended September 30, 2019 were $19.4~~a $55.6 million ~~or 3%, higher than total net revenues for the nine months ended September 30, 2018. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.~~

Net production volumes for oil, natural gas and NGLs increased 27%, 32% and 29%, respectively, between periods. The oil volume increase resulted primarily from our drilling success in the Delaware Basin. Since the third quarter 2018, 79 gross operated wells were placed on production in the Delaware Basin, which added 5,024 MBbls of net oil production to the first nine months of 2019. These oil volume increases were partially offset by normal field production declines across our existing wells.

Natural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. As a result, our natural gas production increased 32% and NGL production increased 29% during the first nine months of 2019 compared to the same prior year period.

The above increases in production volumes between periods were partially offset by lower average realized sales prices for oil, natural gas and NGLs for the first nine months of 2019 compared to the same 2018 period. The average price for oil before the effects of hedging decreased 13%, the average price for natural gas before the effects of hedging decreased 49% and the average price for NGLs decreased 42% between periods. The 13% decrease in the average realized oil price was the result of lower NYMEX crude prices between periods (average NYMEX oil prices decreased 15%) partially offset by improved oil differentials (a decrease of $2.01 per Bbl) during the first nine months of 2019. The average realized sales price of natural gas between periods decreased 49% due to lower average NYMEX gas prices between periods (average NYMEX prices decreased 13%) and wider gas differentials (an increase of $0.60 per Mcf). The continued widening of natural gas differentials was due to natural gas pipeline takeaway capacity constraints impacting the Permian Basin, which has in turn depressed natural gas in West Texas. A new gas pipeline was placed into service late in the third quarter of 2019 in the Permian Basin, and continued construction of additional natural gas pipelines are planned through 2021. These third party pipelines are expected to provide relief from these wider natural gas differentials. The overall 42% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products.

~~Operating Expenses.~~ ~~The following table summarizes our operating expenses for the periods indicated:~~

For the Nine Months Ended September 30, Increase/(Decrease)
2019
2018 $ %
Operating costs (in thousands):

Lease operating expenses $ 107,077

$ 59,164
$ 47,913
81 %
Severance and ad valorem taxes 45,519

42,791
2,728
6 %
Gathering, processing and transportation expenses 52,120

45,214
6,906
15 %
Operating costs per Boe:

Lease operating expenses $ 5.24

$ 3.72
$ 1.52
41 %
Severance and ad valorem taxes 2.23

2.69
(0.46 ) (17 )%
Gathering, processing and transportation expenses 2.55

2.85
(0.30 ) (11 )%

~~Lease Operating Expenses.~~ LOE for the nine months ended September 30, 2019 increased $47.9 million as compared to the nine months ended September 30, 2018. Higher LOE for the first nine months of 2019 was primarily related to a $31.1 million increase in expense associated with our higher well count. We had 319 gross operated horizontal wells as of September 30, 2019 compared to 240 gross operated horizontal wells as of September 30, 2018. The net increase in well count was mainly the result of our drilling activity adding 79 gross operated wells since the third quarter of 2018, which was further adjusted for acquisitions and divestitures. In addition, workover activity increased $16.8 million between periods as a result of our higher well count and related higher workover activity.

LOE on a per Boe basis increased when comparing the first nine months of 2019 to the same 2018 period. LOE per Boe was $5.24 for the nine months ended September 30, 2019, which represents an increase of $1.52 per Boe from the comparable 2018 period. This increase in rate was mainly due to our higher level of workover activity discussed above, as well as (i) a decline in the ratio of flush production to base production based on our level of D&C activity in 2019; (ii) higher monthly rental rates for ESPs and wellhead generators, (iii) increased wellhead chemical costs, and (iv) increased number of field employees, resulting in higher labor costs.

~~Severance and Ad Valorem Taxes.~~ Severance and ad valorem taxes for the nine months ended September 30, 2019 increased $2.7 million compared to the nine months ended September 30, 2018. Severance taxes are primarily based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the valuation of our proved developed oil and natural gas properties and vary across the different counties in which we operate. Severance and ad valorem taxes as a percentage of total net revenues increased to 6.6% for the nine months ended September 30, 2019 as compared to 6.4% in 2018 period. Ad valorem taxes increased $5.3 million between periods as a result of our higher well count and higher oil and gas property values. These increases in ad valorem taxes were partially offset by lower severance taxes of $2.6 million between periods primarily related to tax credits received in the first nine months of 2019 from wells that qualified for the “high-cost gas well” exemption, whose criteria are defined by the Texas Railroad Commission.

Severance and ad valorem taxes decreased on a per Boe basis to $2.23 for the nine months ended September 30, 2019 from $2.69 for the nine months ended September 30, 2018. This 17% decrease in rate is due to lower average realized sales prices for oil, natural gas and NGLs between periods.

~~Gathering, Processing and Transportation Expenses.~~ GP&T for the nine months ended September 30, 2019 increased $6.9 million compared to the nine months ended September 30, 2018 due to higher natural gas and NGL volumes sold between periods, which in turn resulted in a higher amount of plant processing costs, transportation tariffs and gathering fees being incurred.

On a per Boe basis, GP&T decreased 11% from $2.85 for the first nine months of 2018 to $2.55 per Boe for the same 2019 period. On a natural gas and NGL volume basis (i.e. excluding crude oil barrels) the Boe rate likewise decreased between periods to $5.80 from $6.56 for the nine months ended September 30, 2019 and 2018, respectively. This decrease was attributable to the following factors: (i) lower natural gas prices between periods, as residue gas is a primary cost component of gas processing fees; and (ii) $11.9 million in reimbursements received from third parties for their usage of our firm transportation capacity in the first nine months of 2019, which were not similarly received in 2018. The agreement that enables us to receive these third party reimbursements extends through March of 2020; such reimbursements, however, may not necessarily be recurring in these similar amounts.

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

For the Nine Months Ended September 30,
(in thousands, except per Boe data) 2019 2018
Depreciation, depletion and amortization $ 321,392
$ 224,379
Depreciation, depletion and amortization per Boe $ 15.73
$ 14.12

DD&A rate can fluctuate as a result of finding and development costs, acquisitions, impairments, as well as changes in proved reserve or proved developed reserves. For the nine months ended September 30, 2019, DD&A expense amounted to $321.4 million, an increase of $97.0 million over the same 2018 period. The primary factor contributing to higher DD&A in 2019 was the increase in our overall production volumes between periods, which added $64.3 million of incremental DD&A expense during the first nine months of 2019, while higher DD&A rates between periods contributed an additional $32.7 million of DD&A expense to the first nine months of 2019.

DD&A per Boe was $15.73 for the nine months of 2019 compared to $14.12 for the same period in 2018. The primary factors contributing to this higher DD&A rate were (i) revisions to proved and proved developed reserves subsequent to the third quarter of 2018 and (ii) a higher level of infrastructure costs (having no associated proved reserve adds).

~~Impairment and Abandonment Expenses.~~ During the nine months ended September 30, 2019, $42.4 million of impairment and abandonment expense was incurred related to undeveloped leasehold acreage. This expense consisted of the following: (i) $19.1 million related to non-core acreage that expired during the first nine months of 2019 after efforts to extend, sell or trade these leases were unsuccessful, (ii) $16.6 million for impaired acreage following an acreage sale initiatedallowance in the first quarter of ~~2019, and (iii) $6.7 million related~~2020 against deferred tax assets that are not expected to ~~the amortization of leasehold expiration costs associated with individually insignificant unproved properties.~~

During the nine months ended September 30, 2018, $10.4 million of abandonment expense was incurred related to undeveloped leasehold acreage that expired during the period after efforts to extend, sell or trade these leases were unsuccessful.

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

For the Nine Months Ended September 30,
(in thousands) 2019
2018
Geological and geophysical costs $ 7,212
$ 6,308
Stock-based compensation 2,034
1,323
Exploratory dry hole costs —
395
Exploration expense $ 9,246
$ 8,026

Exploration was $9.2 million for the nine months ended September 30, 2019 compared to $8.0 million for the same prior year period. Exploration expense mainly consists of topographical studies, G&G projects, and salaries and expenses of G&G personnel. The period over period increase in exploration expense was primarily due to an increase in G&G personnel expenses of $2.2 million during the first nine months of 2019 due to the average number of geologists increasing between periods. This increase was partially offset by lower costs incurred on G&G projects and seismic studies between periods and no exploratory dry hole costs incurred during 2019.

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

For the Nine Months Ended September 30,
(in thousands) 2019
2018
Cash general and administrative expenses $ 37,272
$ 31,661
Stock-based compensation 19,317
13,006
General and administrative expenses $ 56,589
$ 44,667

G&A expenses for the nine months ended September 30, 2019 were $56.6 million compared to $44.7 million for the nine months ended September 30, 2018. The higher G&A expenses incurred in 2019 were primarily due to $4.4 million in increased employee salaries, wages and payroll burdens, $6.3 million in higher stock-based compensation and $1.7 million in increased software costs and office rental expenses. These costs were higher during the first nine months of 2019 due to our increase in headcount since September 30, 2018.

~~Other Income and Expenses.~~

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

For the Nine Months Ended September 30,
(in thousands) 2019 2018
Credit facility $ 6,179
$ 2,835
5.375% Senior Notes due 2026 16,124
16,125
6.875% Senior Notes due 2027 18,716
—
Amortization of debt issuance costs and debt discount 2,070
1,258
Interest capitalized (3,246 ) (2,080 )
Total $ 39,843
$ 18,138

Interest expense was $21.7 million higher for the nine months ended September 30, 2019 compared to the same 2018 period primarily due to $18.7 million in interest we incurred in the first nine months of 2019 related to our 2027 Senior Notes that were issued in March 2019, as well as increased borrowings under our credit facility in the first nine months of 2019. Our weighted average borrowings outstanding under our credit facility were $138.3 million and $45.2 million for the first nine months of 2019 and 2018, respectively. Our credit facility’s weighted average effective interest rate was 3.9% for the nine months ended September 30, 2019 as compared to 3.7% for the same 2018 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 the forward price curve for underlying commodities and (ii) monthly cash settlements of our hedged derivative positions.

~~The following table presents gains and losses for derivative instruments for the periods indicated:~~

For the Nine Months Ended September 30,
(in thousands) 2019 2018
Cash settlement gains (losses) $ (2,207 ) $ 14,390
Non-cash mark-to-market derivative gain (loss) (14 ) 579
Total $ (2,221 ) $ 14,969

~~Income Tax Expense~~. During the nine months ended September 30, 2019 and 2018, we recognized income tax expense of $5.1 million and $50.7 million, respectively. The decrease in income tax expense for the nine months ended September 30, 2019 as compared to the same period in 2018 was primarily due to a decrease in pre-tax income of $218.8 million between periods, which was partially offset by a $5.7 million discrete permanent item in the first nine months of 2019 that had the effect of increasing income tax expense for that period.

~~Our provision for income taxes for the first nine months of 2019 and 2018 differed from the amount that would~~ be ~~provided by applying the statutory U.S. federal tax rate of 21% to pre-tax income because of state income taxes and permanent differences.~~realized.

Liquidity and Capital Resources

Overview

Our drilling and completion and land acquisition activities require us to make significant capital expenditures. Historically, our primary sources of liquidity have been cash flows from operations, borrowings under CRP’s revolving credit facility, and proceeds from offerings of debt or equity securities. Future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly in March 2020 and have continued to deteriorate and have remained low since. These lower commodity prices negatively impact our cash flows and availability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary use of capital has been for drilling and development capital expenditures and the acquisition of oil and natural gas properties.

The following table summarizes our capital expenditures (“capex”) incurred for the ~~nine~~three months ended ~~September 30, 2019:~~March 31, 2020:


(in millions)	For the Nine Months Ended September 30, 2019		Three Months Ended March 31, 2020
Drilling and completion capital expenditures	$	528.7	$	146.8
Facilities, infrastructure and other	130.8		25.2
Land	35.2		3.4
Total capital expenditures	$	694.7	$	175.4

We continually evaluate our capital needs and compare them to our capital resources. ~~Our~~ As a result of the recent decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we have recently suspended all drilling and completion activities in order to preserve capital. Specifically, we recently reduced our operated drilling rig program to zero rigs, which is down from the four-rig program that we announced with our 2020 operational guidance. Consequently, we expect that our total capex budget for 2020 will be between $240.0 million to $290.0 million, which represents an approximate 60% reduction from the mid-point of our original estimated capex budget for ~~2019 is $765~~2020 of $590 million to ~~$925~~$690 million of which $625 million to $725 million is allocated to drilling and completion (“D&C”) activity. We expect to fund our capex budget with cash flows from operations and borrowings under our credit facility. The D&C portion of our 2019 capital budget represents a decrease relative to $766.1 million of D&C expenditures incurred during 2018. This decreased capital budget is due to running fewer drilling rigs in 2019 versus 2018..

Because we are the operator of a high percentage of our acreage, we can control the amount and timing of ~~these~~our capital expenditures. We ~~could~~can choose to defer or accelerate a portion of ~~this~~our planned capex 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; oil storage or transportation constraints; the success of our drilling activities; 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~~Given the weakness in realized oil prices, we are actively evaluating whether to voluntarily curtail or shut-in a substantial portion of our current ~~oil~~production volumes, and ~~natural gas price expectations for~~we expect to voluntarily curtail up to 40% of our production during the month of May. Further potential curtailment decision will continue to be evaluated and made on a month-to-month basis subject to market conditions, storage and transportation constraints, and contractual obligations. Any decision in the future to further curtail or shut-in our production could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditure.

We expect to fund the remainder of ~~2019, we believe that~~ our 2020 capital expenditures with cash flows from operations ~~proceeds from the issuance of the 2027 Senior Notes~~ and borrowings under our credit facility will provide us with sufficient liquidity to execute our current capital program. However, our future cash flows are subject to a number of variables, including the future level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties.Credit Agreement. We cannot ensure that cash flows from operations ~~and other needed capital~~ will be available or other sources of needed capital on acceptable terms or at all. InFurther, our ability to access the ~~event we make additional acquisitions~~public or private debt or equity capital markets on economic terms in the future will be affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the ~~amount~~value and performance of ~~capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce~~ our 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-based borrowings and debt offerings. If we require additional capital to fund acquisitions, we may also seek such capital through traditional reserve-based borrowings, offerings of debt or equity securities, ~~asset sales, or~~prevailing commodity prices and other ~~means. If~~macroeconomic factors outside of our control.

Moreover, to manage our future financing cash outflows and liquidity position, we ~~are unable~~have initiated the Exchange Offers with respect to ~~obtain funds when needed or on acceptable terms, we may be required to curtail~~ our ~~drilling program,~~Senior Notes in April 2020 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 maintainif successful, would lower our ~~production or replace our reserves.~~outstanding debt and future interest payments.

Analysis of Cash Flow Changes

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


	For the Nine Months Ended September 30,						Three Months Ended March 31,
(in thousands)	2019			2018			2020			2019
Net cash provided by operating activities	$	384,875		$	494,695		$	100,818		$	101,028
Net cash used in investing activities	(698,120		)	(694,966		)	(166,976		)	(218,878		)
Net cash provided by financing activities	308,064			135,511			59,792			189,186

For the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, we generated ~~$384.9~~$100.8 million of cash from operating activities, a decrease of ~~$109.8~~only $0.2 million from the same period in ~~2018.~~2019. Cash provided by operating activities decreased primarily due to lower realized prices for crude oil, natural gas and NGLs, lower NGL production volumes, higher lease operating expenses, ~~severance and ad valorem~~production taxes, GP&T costs, exploration expense, cash ~~general~~G&A expenses, and ~~administrative expenses,~~the timing of supplier payments during the three months ended March 31, 2020. These declining factors were partially offset by higher crude oil and natural gas production volumes, lower interest payments, lower cash settlement losses from derivatives, and the timing of our receivable collections ~~during~~for the ~~nine~~three months ended ~~September 30, 2019. These declining factors were partially offset by higher crude oil, natural gas and NGL production volumes and the timing of supplier payments for the nine months~~

~~ended September 30, 2019~~March 31, 2020 as compared to the same ~~2018~~2019 period. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for more information on fluctuations in our operating expenses between periods.

During the ~~nine~~three months ended ~~September 30,~~March 31, 2020, cash flows from operating activities, cash on hand, and net borrowings of $60.0 million under our credit facility were used to finance $161.9 million of drilling and development capex and to fund $5.8 million in oil and gas property acquisitions.

During the three months ended March 31, 2019, cash flows from operating activities, cash on hand, proceeds from sales of oil and gas properties and proceeds from the issuance of our 2027 Senior Notes were used to repay net borrowings of ~~$180.0~~$300.0 million under our credit facility, to finance ~~$644.9 million of drilling and development capex, to fund $73.3 million in oil and gas property acquisitions and to purchase $8.2 million of other property and equipment.~~

During the nine months ended September 30, 2018, cash flows from operating activities, cash on hand, proceeds from sales of oil and gas properties and $140.0 million in net borrowings under our credit facility were used to finance $723.1$217.2 million of drilling and development capex and ~~$114.9~~to fund $25.7 million in oil and gas property acquisitions.

Credit Agreement

On May 4, 2018, CRP, our consolidated subsidiary, entered into an amended and restated credit agreement with a syndicate of banks that as of ~~September 30, 2019,~~March 31, 2020 had a borrowing base of $1.2 billion and elected commitments of $800.0 million. The credit agreement provides for a five-year secured revolving credit facility, maturing on May 4, 2023. As of ~~September 30, 2019,~~March 31, 2020, we had ~~$120.0~~$235.0 million borrowings outstanding and ~~$679.2~~$564.2 million in available borrowing capacity, which was net of $0.8 million in letters of credit outstanding.

On May 1, 2020, we entered into the Amendments with the lenders to the existing credit agreement. Pursuant to the Amendments, the borrowing base and elected commitment were reduced to $700.0 million. In addition, to the extent that the Exchange Offers close, the Amendments introduce a minimum availability condition to borrowing at the lesser of $100.0 million and 25% of the aggregate principal amount of New Notes outstanding from the Exchange Offers. If the minimum availability condition to borrowing were to be determined at its maximum level of $100.0 million, it would have the resulting effect of limiting the amount of borrowings that CRP could draw against its $700.0 million credit facility to $600.0 million. Among other things, the Amendments also suspended the total funded debt to EBITDAX ratio (as specified in the existing credit agreement) through year-end 2021, introduced a new financial covenant testing the ratio of first lien debt to EBITDAX, and permitted the issuance of new senior secured notes in connection with the ~~fall 2019 semi-annual borrowing base redetermination under our credit facility, the borrowing base was reaffirmed at $1.2 billion and the amount of elected commitments remained at $800.0 million.~~Exchange Offers described below.

CRP’s credit agreement contains restrictive covenants that limit its ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make or declare dividends; (v) enter into commodity hedges exceeding a specified percentage of CRP’s expected production; (vi) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (vii) incur liens; (viii) sell assets; and (ix) engage in transactions with affiliates.

CRP’s credit agreement also requires it to maintain compliance with the following financial ratios: (i) a current ratio, which is the ratio of CRP’s consolidated current assets (including unused commitments under its revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the credit agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and (ii) a leverage ratio, which is the ratio of Total Funded Debt (as defined in CRP’s credit agreement) to consolidated EBITDAX (as defined in CRP’s credit agreement) for the rolling four fiscal quarter period ending on such day, of not greater than 4.0 to 1.0. CRP was in compliance with these covenants and the financial ratios described above as of ~~September 30, 2019~~March 31, 2020 and through the filing of this Quarterly Report.

For further information on ~~our~~the credit agreement and related Amendments, refer to Note 3—4—Long-Term Debt and Note 14—Subsequent Events under Part I, Item I of this Quarterly Report.

Senior Notes

On November 30, 2017, CRP issued $400.0 million of 5.375% senior notes due 2026 ~~(the “2026 Senior Notes”)~~ and on March 15, 2019, CRP issued $500.0 million of 6.875% senior notes due 2027 ~~(the “2027 Senior Notes” and collectively with the 2026 Senior Notes the “Senior Notes”)~~ in 144A private placements. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of CRP’s current subsidiaries that guarantee CRP’s revolving credit facility. The Senior Notes are not guaranteed by Centennial, nor are we subject to the terms of the indentures governing the Senior Notes.

stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with these covenants as of ~~September 30, 2019~~March 31, 2020 and through the filing of this Quarterly Report.

On April 22, 2020, we commenced the Exchange Offers to all eligible holders of our Senior Notes to exchange any and all of our outstanding Senior Notes held for up to $250.0 million aggregate principal amount of newly issued 8% Second Lien Senior Secured Notes due 2025 and up to $200.0 million aggregate principal amount of newly issued 8% Third Lien Senior Secured Notes due 2027. The transaction is currently expected to close on May 22, 2020, subject to customary closing conditions. For further information on our Senior Notes and the Exchange Offers, refer to Note 3—4—Long-Term Debt and Note 14—Subsequent Events under Part I, Item I of this Quarterly Report.

Contractual Obligations

Our contractual obligations include operating and transportation agreements, drilling rig ~~commitments,~~contracts, office and equipment leases, ~~water disposal agreements, purchase obligations,~~ asset retirement obligations, long-term debt obligations and cash interest expense on long-term debt obligations, ~~and transportation and gathering agreements.~~which we routinely enter into, modify or extend. Since December 31, ~~2018~~2019, there have not been any significant, non-routine changes in our contractual ~~obligations, other than the issuance of 2027 Senior Notes and their related interest obligations as discussed in~~ obligations.~~Note 3—Long-Term Debt~~ ~~under Part I, Item 1. of this Quarterly Report.~~

Critical Accounting Policies and Estimates

There have been no material changes during the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 to the critical accounting policies previously disclosed in our ~~2018~~2019 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 ~~2018~~2019 Annual Report for a discussion of our critical accounting policies and estimates.

New Accounting Pronouncements

~~Please refer to~~ ~~Note 1—Basis of Presentation~~ ~~under Part I, Item 1. of this Quarterly Report for a discussion of the effects of recently adopted~~There were no significant new accounting standards ~~and the potential effects of~~adopted or new accounting ~~pronouncements.~~pronouncements that would have a potential effect on us as of March 31, 2020.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The term “market risk” as it applies to our business refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates, and we are exposed to market risk 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 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 primary market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue infor the foreseeable future. Based on our production for the first ~~nine~~three months of ~~2019,~~2020, our oil and gas sales for the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 would have moved up or down ~~$59.0~~$17.1 million for each 10% change in oil prices per Bbl, ~~$6.6~~$1.4 million for each 10% change in NGL prices per Bbl, and ~~$3.2~~$0.8 million for each 10% change in natural gas prices per Mcf.

Due to this volatility, we have historically used, and we may elect to continue to selectively use, commodity derivative instruments (such as collars, swaps and basis swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flows 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, but alternatively they may partially limit our potential gains from future increases in prices. Our credit agreement limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated projected production from proved properties.

The following table summarizes the terms of the swap contracts we had in place as of ~~September 30, 2019~~March 31, 2020 and additional contracts entered into through ~~October 31, 2019.~~May 1, 2020. Refer to Note ~~7-Derivative~~7—Derivative Instruments in Item 1 of Part I of this Quarterly Report for open derivative positions as of ~~September 30, 2019~~March 31, 2020:

Period
Volume (Bbls)
Volume (Bbls/d)
Weighted Average Differential
($/Bbl)⁽¹⁾
Crude oil basis swaps October 2019 - December 2019
920,000

10,000

$ (4.24 )
January 2020 - March 2020 273,000
3,000
0.67
April 2020 - June 2020 273,000
3,000
0.67
July 2020 - September 2020 276,000
3,000
0.67
October 2020 - December 2020 276,000
3,000
0.67



	Period	Volume (Bbls)	Volume (Bbls/d)	Weighted Average Fixed Price ($/Bbl)⁽¹⁾
Crude oil swaps	April 2020 - June 2020	2,852,000	31,341	$	26.14
	July 2020 - September 2020	2,300,000	25,000	26.83
	October 2020 - December 2020	184,000	2,000	36.36

	Period	Volume (Bbls)	Volume (Bbls/d)	Weighted Average Differential ($/Bbl)⁽²⁾
Crude oil basis swaps	April 2020 - June 2020	543,000	5,967	$	1.12
	July 2020 - September 2020	644,000	7,000	0.63
	October 2020 - December 2020	644,000	7,000	0.63


⁽¹⁾	These crude oil swap transactions are settled based on the NYMEX WTI price as of the specified settlement date.


⁽²⁾	These oil basis swap transactions are settled based on the difference between the arithmetic average of ~~the~~ ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable settlement period.

Period
Volume (MMBtu)
Volume (MMBtu/d)
Weighted Average Fixed Price
($/MMBtu)⁽¹⁾
Natural gas swaps - Henry Hub October 2019 - December 2019
2,760,000

30,000

$ 2.78
Natural gas swaps - West Texas WAHA October 2019 - December 2019
1,380,000

15,000

1.61

Period
Volume (MMBtu)
Volume (MMBtu/d)
Weighted Average Differential
($/MMBtu)⁽²⁾
Natural gas basis swaps October 2019 - December 2019
3,220,000

35,000

$ (1.31 )



	Period	Volume (MMBtu)	Volume (MMBtu/d)	Weighted Average Fixed Price ($/MMBtu)⁽¹⁾
Natural gas swaps	April 2020 - June 2020	2,730,000	30,000	$	2.03
	July 2020 - September 2020	2,760,000	30,000	2.03
	October 2020 - December 2020	930,000	10,109	2.03

	Period	Volume (MMBtu)	Volume (MMBtu/d)	Weighted Average Differential ($/MMBtu)⁽²⁾
Natural gas basis swaps	April 2020 - June 2020	2,730,000	30,000	$	(1.62	)
	July 2020 - September 2020	2,760,000	30,000	(1.62		)
	October 2020 - December 2020	930,000	10,109	(1.62		)


⁽¹⁾	These natural gas swap contracts are settled based ~~on either i) the~~ NYMEX Henry Hub price ~~or ii) the Inside FERC West Texas WAHA price of natural gas, as applicable,~~ as of the specified settlement date.


⁽²⁾	These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas during each applicable settlement period.

Changes in the fair value of derivative contracts from December 31, ~~2018~~2019 to ~~September 30, 2019,~~March 31, 2020, are presented below:


(in thousands)	Commodity derivative asset (liability)			Commodity derivative asset (liability)
Net fair value of oil and gas derivative contracts outstanding as of December 31, 2018	$	(4,419	)
Net fair value of oil and gas derivative contracts outstanding as of December 31, 2019				$	(325	)
Contracts settled	2,207			53
Change in the futures curve of forecasted commodity prices⁽¹⁾	(2,221		)	(8,505		)
Net fair value of oil and gas derivative contracts outstanding as of September 30, 2019	$	(4,433	)
Net fair value of oil and gas derivative contracts outstanding as of March 31, 2020				$	(8,777	)


⁽¹⁾	At inception, new derivative contracts entered into by us have no intrinsic value.

A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of ~~September 30, 2019~~March 31, 2020 would cause a less than ~~$0.1~~$13.6 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, 2019~~March 31, 2020 would cause a $0.6 million increase or decrease, respectively, in this same fair value liability.

Interest Rate Risk

Our ability to borrow and the rates offered by lenders can be adversely affected by deteriorations in the credit markets and/or downgrades in our credit rating. The uncertainties regarding the impact of COVID-19 as well as the significant decline in global oil and gas prices in March and April of 2020 has impacted the credit markets, resulting in increases in market interest rates for new debt issuances. CRP’s credit facility interest rate, on the other hand, is based on a LIBOR spread, which exposes us to interest rate risk ~~if we have~~on our borrowings ~~outstanding.~~outstanding to the extent LIBOR increases.

As of ~~September 30, 2019,~~March 31, 2020, we had ~~$120.0~~$235.0 million of debt outstanding under our credit agreement, with a weighted average interest rate of ~~3.3%~~2.1%. 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 ~~$1.2~~$2.4 million per year. We do not currently have or intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.

The remaining long-term debt balance of ~~$881.9~~$882.9 million consists of our Senior Notes, which have fixed interest ~~rates; therefore,~~rates. Therefore, this balance is not affected by interest rate movements. For additional information regarding our debt instruments, see Note 3—4—Long-Term Debt, in Item 1 of Part I of this Quarterly Report.

Item 4. Controls and Procedures

Evaluation of Disclosure Control and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Exchange Act, we have evaluated, under the supervision and with the participation of 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, 2019.~~March 31, 2020. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed 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, 2019~~March 31, 2020 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in the system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) during the three months ended ~~September 30, 2019~~March 31, 2020 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we are party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment-related disputes. While the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our ~~2018~~2019 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings ~~which could materially affect~~as well as additional risk factors set forth below. Other than with respect to the additional risk factors below, there have been no material changes in our ~~businesses, financial condition, or future results.~~risk factors from those described in our 2019 Annual Report. The risks described in the 2019 Annual Report and below are not the only risks facing us. 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~~

The excess supply of oil and natural gas resulting from the reduced demand caused by the COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries may result in transportation and storage constraints, reduced production and shut-in of our wells, any of which would adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.

The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have ~~been~~resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by the curtailment agreements amongst OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. To the extent that the outbreak of COVID-19 continues to negatively impact demand and OPEC members, other oil exporting nations, and oil producers fail to implement production cuts or take other actions that are sufficient to support and stabilize commodity prices, we expect there to be excess supply of oil and natural gas for a sustained period.

This excess supply could, in turn, result in transportation and storage capacity constraints in the United States, or even the elimination of available storage, including in the Permian Basin. If, in the future, our transportation or storage arrangements become constrained or unavailable, we may incur significant operational costs if there is an increase in price for services or we may be required to shut-in or curtail production or flare our natural gas. In addition, given the weakness in realized oil prices, we are actively evaluating whether to voluntarily curtail or shut-in a substantial portion of our current production volumes, and we expect to voluntarily curtail up to 40% of our production during the month of May. Further potential curtailment decisions will continue to be evaluated and made on a month-to-month basis subject to market conditions, storage or transportation constraints, and contractual obligations. Our actions to shut-in wells may result in obligations to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Further, any prolonged shut-in of our

wells may result in materially decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. These impacts on our operations, together with the lower price we receive for our continuing production of oil and gas, could impact our ability to comply with the covenants under CRP’s credit agreement and Senior Notes. All of these impacts resulting from the confluence of the COVID-19 pandemic and the price war between Saudi Arabia and Russia may adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.

Due to the commodity price environment, we have postponed or eliminated a portion of our developmental drilling. A sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, will require us to reevaluate and further postpone or eliminate additional drilling. Such actions would likely result in the reduction of our proved undeveloped reserves and related reserve values and a reduction in our ability to service our debt obligations.

Additionally, as of December 31, 2019, approximately 13% of our total net acreage was not held by production and we had leases representing 3,162 and 3,750 undeveloped net acres scheduled to expire during 2020 and during 2021, respectively, in each case assuming no exercise of lease extension options where applicable. Our actions to curtail production and shut-in wells, together with any further curtailments we may implement in the future, may result in our inability to continue to hold such leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.

The inability to complete our pending divestiture of our saltwater disposal wells and associated produced water infrastructure on the initial terms agreed to by the parties or in the expected time frame may adversely affect our business and financial condition.

On February 24, 2020, we entered into a purchase and sale agreement with a subsidiary of WaterBridge Resources LLC (“WaterBridge”) to divest our saltwater disposal wells and associated produced water infrastructure in Reeves County for $225.0 million, consisting of $150.0 million in cash at closing and an additional $75 million payable to us on a deferred basis upon meeting certain incentive thresholds. We believe the uncertain macro environment for the oil and gas industry and resulting changes to commodity prices and drilling and completion activity in the Delaware Basin, increase the risk that the transaction fails to close on the original timeframe and terms agreed to between us and WaterBridge. While the transaction currently remains pending, either party may terminate the transaction if closing does not occur on or before May 15, 2020. If the transaction fails to close on the initial terms agreed to between us and WaterBridge, our business and financial condition may be adversely affected. In particular, to the extent the transaction is terminated, or if we receive lower cash consideration than originally planned, then the amount of cash that we may allocate to the repayment of outstanding borrowings under our revolving credit facility or to the funding of our capital budget, and the timing of such repayment or funding, will also be affected.

Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices.

Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. We have entered into fixed price oil swaps for April through December of 2020 to protect against possible, additional near-term declines in oil prices. During this period, CRP has hedged an average of approximately 19,400 barrels per day of oil at a weighted average price of $26.79 per Bbl. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices which would have a material negative impact on our results of operations.

If commodity prices continue to decrease or remain at current levels such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take additional write-downs of the carrying values of our properties.

Accounting guidance requires that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. Due to the recent depressed commodity prices, we expect to record a material non-cash impairment to the carrying value of our oil and natural gas properties, which will have an adverse effect on our results of operations. Further impairments will be required if oil and natural gas prices remain low or decline further, our undeveloped property leases expire in whole or in part, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and gas properties otherwise exceeds the present value of estimated future net cash flows.

The Pre-Tax PV10% of our proved reserves at December 31, 2019 may not be the same as the current market value of our estimated oil, natural gas and NGLs reserves.

You should not assume that the Pre-Tax PV10% value of our proved reserves as of December 31, 2019 as disclosed in our 2019 Annual Report is the current market value of our estimated oil, natural gas and NGLs reserves. We base the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

the actual prices we receive for oil, natural gas and NGLs;

the actual development and production expenditures;

the amount and timing of actual production; and

changes in governmental regulations or taxation.

The timing of both our ~~risk factors from those described in our 2018 Annual Report or our other SEC filings.~~

~~Item 5. Other Information~~

~~On October 29, 2019, the board of directors of the Company approved the Centennial Resource Development, Inc. Amended~~production and ~~Restated Severance Plan (the “Amended Plan”). Under the Amended Plan, all of the Company’s full-time employees, including the named executive officers, are eligible for benefits~~expenses incurred in connection with ~~a Qualifying Termination~~the development and production of ~~employment following a Change~~oil and natural gas properties will affect the timing and amount of ~~Control (as such capitalized terms are defined~~actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating Pre-Tax PV10% may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the Amended Plan). The Amended Plan amends and restates in its entirety the Centennial Resource Development, Inc. Severance Plan that became effective on May 2, 2018 to (a) increase the cash severance payable to employees that experience a Qualifying Termination following a Change of Control, (b) broaden the definition of “Qualifying Termination” as it relates to non-officer employees to include situations where an employee resigns for Good Reason (as definedpresent value estimates included in the ~~Amended Plan),~~Annual Report, which could have a material effect on the value of our reserves. The oil and ~~(c) provide for~~natural gas prices used in computing our Pre-Tax PV10% as of December 31, 2019 under SEC guidelines were $52.19 per Bbl and $2.58 per MMBtu, respectively, before price differentials. Using more recent prices in estimating proved reserves results in a reduction in proved reserve volumes due to economic limits, which would further reduce the ~~potential reduction~~Pre-Tax PV10% value of ~~benefits in certain instances to avoid excise tax liability.~~

Under the Amended Plan, if one of the Company’s named executive officers experiences a Qualifying Termination, the named executive officer is entitled to cash severance in an amount equal to 225% (or, in the case of the Chief Executive Officer, 275%) of the executive officer’s annual base salary, ~~plus~~ 225% (or, in the case of the Chief Executive Officer, 275%) of the average of the actual annual performance bonuses paid to the executive officer in the three full fiscal years prior to the year of termination. The Amended Plan makes no changes to the healthcare continuation benefits, outplacement benefits or equity treatment benefits that the named executive officers are entitled to receive following a Qualifying Termination, all of which is described in the Company's 2019 Proxy Statement.our proved reserves.

The ~~foregoing description~~marketability of our production is ~~qualified~~dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, or if we are unable to access these facilities on commercially reasonable terms, our operations could be interrupted and our revenues reduced.

The marketability of our oil, natural gas and NGL production depends in ~~its entirety~~part upon the availability, proximity, capacity and availability of transportation and storage facilities owned by ~~reference~~third parties. In general, we do not control these facilities, and our access to them may be limited or denied. Our oil production is generally transported from the wellhead to our tank batteries by a gathering system. Our purchasers then transport the oil by pipeline to a larger pipeline for transportation to markets. The majority of our natural gas production is generally transported by gathering lines from the wellhead to a central delivery point and is then gathered by third-party lines to a gas processing facility. We do not control these third-party transportation, gathering or processing facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our production and thereby cause a significant interruption in our operations.

If we cannot meet the continued listing requirements of the NASDAQ, the NASDAQ may delist our common stock, which would have an adverse impact on the trading volume, liquidity and market price of our common stock.

On April 21, 2020, we received written notification (the “Notice”) from the Listing Qualifications Department of the Nasdaq Stock Market LLC (“Nasdaq”) indicating that, for the last thirty consecutive business days, the bid price for our Class A Common Stock, par value $0.0001 per share (our “Common Stock”), had closed below the minimum $1.00 per share requirement for continued listing on the Nasdaq Capital Market under Nasdaq Listing Rule 5550(a)(2) (the “Minimum Bid Requirement”). The Notice has no immediate effect on the listing or trading of our Common Stock on the Nasdaq Capital Market. In accordance with Nasdaq Listing Rule 5810(c)(3)(A), we were provided an initial period of 180 calendar days, or until October 19, 2020, to regain compliance. However, due to recent market turmoil, Nasdaq has filed a rule change tolling the compliance periods for price-based listing requirements through June 30, 2020, extending our compliance period until December 28, 2020.

If we do not regain compliance with the Minimum Bid Requirement by December 28, 2020, we may be eligible for an additional 180 calendar day compliance period. To qualify, we would be required to meet the continued listing requirement for market value of publicly held shares and all other initial listing standards for the Nasdaq Capital Market, with the exception of the bid price requirement, and would need to provide written notice of our intention to cure the deficiency during the second compliance period. However, if it appears to the ~~full text~~Nasdaq staff that we will not be able to cure the deficiency, or if we do not meet the other listing standards, Nasdaq could provide notice that our Common Stock will become subject to delisting. In the event we receive notice that our Common Stock is being delisted, Nasdaq rules permit us to appeal any delisting determination by the Nasdaq staff to a Hearings Panel.

We intend to actively monitor the closing bid price of our Common Stock and will evaluate available options to regain compliance with the Minimum Bid Requirement. There can be no assurance that we will be able to regain compliance with the Minimum Bid Requirement or maintain compliance with the other listing requirements of the ~~Amended Plan, a copy~~Nasdaq. If our Common Stock ultimately were to be delisted for any reason, it could negatively impact us as it would likely reduce the liquidity and market price of ~~which is attached hereto as Exhibit 10.3~~our Common Stock; reduce the number of investors willing to hold or acquire our Common Stock; and ~~is incorporated herein by reference.~~negatively impact our ability to access equity markets and obtain financing.

Item 6. Exhibits



Exhibit Number		Description of Exhibit
3.1		Third Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 6, 2019).
3.2		Second Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on May 1, 2019).
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 Company’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 Company’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 Company’s Annual Report on Form 10-K filed with the SEC on March 23, 2017).
3.6		Amendment No. 3 to Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC dated as of June 15, 2018 (incorporated by reference to Exhibit 3.6 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 6, 2018).
~~10.1#~~4.1		Description of Registrant’s Common Stock (incorporated by reference to Exhibit 4.5 to the Company’s Annual Report on Form 10-K filed with the SEC on February 24, 2020).
10.1*#		Centennial Resource Development, Inc. ~~Second~~ Amended and Restated ~~Non-Employee Director Compensation Program~~Long Term Incentive Plan
10.2		Amendment no. 1 to Purchase and Sale Agreement, dated as of August 2, 2018, between Centennial Resource Production, LLC and BP North America Inc. (incorporated by reference to Exhibit ~~10.2~~10.1 to the ~~Company’s Quarterly~~Registrant’s Current Report on Form ~~10-Q~~8-K filed with the SEC on ~~August 5, 2019).~~
~~10.2#~~		Form of Performance Restricted Stock Unit Agreement under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 5, 2019)March 31, 2020).
10.3*#		Centennial Resource Development, Inc. Third Amended and Restated ~~Severance Plan.~~Non-Employee Director Compensation Program.
10.4		Second Amendment to Second Amended and Restated Credit Agreement, dated as of May 1, 2020, among Centennial Resource Production, LLC, as borrower, Centennial Resource Development, Inc., as parent guarantor, the other guarantors party thereto, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 4, 2020).
10.5		Third Amendment to Second Amended and Restated Credit Agreement and First Amendment to Second Amended and Restated Pledge and Security Agreement, dated as of May 1, 2020, among Centennial Resource Production, LLC, as borrower, Centennial Resource Development, Inc., as parent guarantor, the other guarantors party thereto, JPMorgan Chase Bank, N.A., as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 4, 2020).
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*		Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*		Inline XBRL Taxonomy Extension Schema Document.
101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document.

# Management contract or compensatory plan or agreement.

* Filed herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.



	CENTENNIAL RESOURCE DEVELOPMENT, INC.

	By:	/s/ GEORGE S. GLYPHIS
		George S. Glyphis Vice President, Chief Financial Officer and Assistant Secretary

	Date:	~~November~~May 4, ~~2019~~2020

4748



(in thousands)
Asset retirement obligations as of January 1, 2019	$	13,895
Liabilities acquired	101
Liabilities incurred	1,075
Liabilities divested and settled	(1,112		)
Accretion expense	670
Asset retirement obligations as of September 30, 2019	$	14,629



(in thousands)	Drilling Rigs		Office Leases
2019	$	43,036	$	3,057
2020	4,124		2,830
2021	—		2,761
2022	—		404
Total lease payments	$	47,160	$	9,052



	Period	Volume (Bbls)	Volume (Bbls/d)	Weighted Average Differential ($/Bbl)⁽¹⁾
Crude oil basis swaps	October 2019 - December 2019	920,000	10,000	$	(4.24	)
	January 2020 - March 2020	273,000	3,000	0.67
	April 2020 - June 2020	273,000	3,000	0.67
	July 2020 - September 2020	276,000	3,000	0.67
	October 2020 - December 2020	276,000	3,000	0.67