UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended ~~September~~June 30, ~~2021~~2022

☐ Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission file number 001-37697

CENTENNIAL RESOURCE DEVELOPMENT, INC.

(Exact Name of Registrant as Specified in its Charter)


Delaware						47-5381253
(State of Incorporation)						(I.R.S. Employer Identification No.)

1001 Seventeenth Street, Suite 1800

Denver, Colorado 80202

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

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~~July 31, ~~2021,~~2022, there were ~~284,091,997~~285,059,255 shares of ~~Class A~~ Common Stock, par value $0.0001 per share outstanding.

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		Page
Glossary of Units of Measurements and Industry Terms		3

Cautionary Statement Concerning Forward-Looking Statements		5

Part I—FINANCIAL INFORMATION		7

Item 1.	Financial Statements (Unaudited)	7

	Consolidated Balance Sheets as of ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020~~2021	7

	Consolidated Statements of Operations for the Three and ~~Nine~~Six Months Ended ~~September~~June 30 , 2022 and 2021 ~~and 2020~~	8

	Consolidated Statements of Cash Flows for the ~~Nine~~Six Months Ended ~~September~~June 30 , 2022 and 2021 ~~and 2020~~	9

	Consolidated Statements of Shareholders’ Equity for the Three and ~~Nine~~Six Months Ended ~~September~~June 30 , 2022 and 2021 ~~and 2020~~	11

	Notes to Consolidated Financial Statements	1312

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3429

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5045

Item 4.	Controls and Procedures	5348

Part II—OTHER INFORMATION		5348

Item 1.	Legal Proceedings	5348

Item 1A.	Risk Factors	5348

Item 6.	Exhibits	5455

Signatures		5556

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GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY 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 initiate production.

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.

Extension Well. A well drilled to extend the limits of a known 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.

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.

ICE Brent. Brent crude oil traded on the Intercontinental Exchange, Inc. (ICE).

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.

NEOs. Named executive officers, which term refers to the principal executive officer, the principal financial officer, and the next three most highly paid executive officers of a company as of the end of the most recently completed fiscal year, based on total compensation as determined under Rule 402 of Regulation S-K.

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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.

Realized price. The cash market price less differentials.

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.

SOFR. Secured Overnight Funding Rate.

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

Unproved reserves. Reserves attributable to unproved properties with no proved reserves.

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.

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “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~~ Item 1A. Risk ~~Factors”~~Factors in this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, ~~2020~~2021 (the ~~“2020~~“2021 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 Coronavirus Disease 2019 (“COVID-19”) pandemic and the actions by certain oil and natural gas producing countries;

•political and economic conditions in or affecting other producing regions or countries, including the Middle East, Russia, Eastern Europe, Africa and South America;

•our business strategy and future drilling plans;

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

•our ability to identify, complete and effectively integrate acquisitions of properties or businesses, including our pending merger with Colgate Energy Partners III, LLC;

•our drilling prospects, inventories, projects and programs;

•our financial strategy, leverage, 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 or operating our properties;

•our anticipated rate of return;

•general economic conditions;

•weather conditions in the areas where we operate;

•credit markets;

•uncertainty regarding our future operating results; and

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

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We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in “Item 1A. Risk Factors” in our ~~2020~~2021 Annual Report.

~~Table of Contents~~

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.

Should one or more of the risks or uncertainties described in our ~~2020~~2021 Annual Report occur, or underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any 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.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statement in this section, to reflect events or circumstances after the date of this Quarterly Report.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

CENTENNIAL RESOURCE DEVELOPMENT, INC.

CONSOLIDATED BALANCE SHEETS (unaudited)

(in thousands, except share and per share amounts)


		September 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
ASSETS	ASSETS					ASSETS
Current assets	Current assets					Current assets
Cash and cash equivalents	Cash and cash equivalents	$	4,985	$	5,800	Cash and cash equivalents	$	201,092	$	9,380
Accounts receivable, net	Accounts receivable, net	99,851		54,557		Accounts receivable, net	141,598		71,295

Prepaid and other current assets	Prepaid and other current assets	4,710		5,229		Prepaid and other current assets	7,189		5,860
Total current assets	Total current assets	109,546		65,586		Total current assets	349,879		86,535
Property and Equipment	Property and Equipment					Property and Equipment
Oil and natural gas properties, successful efforts method	Oil and natural gas properties, successful efforts method					Oil and natural gas properties, successful efforts method
Unproved properties	Unproved properties	1,151,552		1,209,205		Unproved properties	984,264		1,040,386
Proved properties	Proved properties	4,662,364		4,395,473		Proved properties	4,929,108		4,623,726
Accumulated depreciation, depletion and amortization	Accumulated depreciation, depletion and amortization	(2,088,128)		(1,877,832)		Accumulated depreciation, depletion and amortization	(2,140,982)		(1,989,489)
Total oil and natural gas properties, net	Total oil and natural gas properties, net	3,725,788		3,726,846		Total oil and natural gas properties, net	3,772,390		3,674,623
Other property and equipment, net	Other property and equipment, net	11,544		12,650		Other property and equipment, net	13,167		11,197
Total property and equipment, net	Total property and equipment, net	3,737,332		3,739,496		Total property and equipment, net	3,785,557		3,685,820
Noncurrent assets	Noncurrent assets					Noncurrent assets
Operating lease right-of-use assets	Operating lease right-of-use assets	17,656		3,176		Operating lease right-of-use assets	54,934		16,385

Other noncurrent assets	Other noncurrent assets	17,807		19,167		Other noncurrent assets	33,660		15,854
TOTAL ASSETS	TOTAL ASSETS	$	3,882,341	$	3,827,425	TOTAL ASSETS	$	4,224,030	$	3,804,594
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities	Current liabilities					Current liabilities
Accounts payable and accrued expenses	Accounts payable and accrued expenses	$	150,611	$	110,439	Accounts payable and accrued expenses	$	208,222	$	130,256

Operating lease liabilities	Operating lease liabilities	1,522		3,155		Operating lease liabilities	21,124		1,413
Derivative instruments						Derivative instruments	83,541		35,150
Other current liabilities	Other current liabilities	76,403		18,274		Other current liabilities	3,214		1,080
Total current liabilities	Total current liabilities	228,536		131,868		Total current liabilities	316,101		167,899
Noncurrent liabilities	Noncurrent liabilities					Noncurrent liabilities
Long-term debt, net	Long-term debt, net	1,004,937		1,068,624		Long-term debt, net	801,849		825,565
Asset retirement obligations	Asset retirement obligations	17,710		17,009		Asset retirement obligations	18,151		17,240
Deferred income taxes	Deferred income taxes	2,589		2,589		Deferred income taxes	50,293		2,589

Operating lease liabilities	Operating lease liabilities	16,689		422		Operating lease liabilities	35,724		16,002
Other noncurrent liabilities	Other noncurrent liabilities	27,232		2,952		Other noncurrent liabilities	32,344		24,579
Total liabilities	Total liabilities	1,297,693		1,223,464		Total liabilities	1,254,462		1,053,874
Commitments and contingencies (Note 11)		0		0
Commitments and contingencies (Note 12)						Commitments and contingencies (Note 12)	0		0
Shareholders’ equity	Shareholders’ equity					Shareholders’ equity

Common stock, $0.0001 par value, 620,000,000 shares authorized:
Class A: 294,280,467 shares issued and 284,084,602 shares outstanding at September 30, 2021 and 290,645,623 shares issued and 278,551,901 shares outstanding at December 31, 2020		29		29

Common stock, $0.0001 par value, 620,000,000 shares authorized; 297,060,327 shares issued and 284,992,650 shares outstanding at June 30, 2022 and 294,260,623 shares issued and 284,696,972 shares outstanding at December 31, 2021						Common stock, $0.0001 par value, 620,000,000 shares authorized; 297,060,327 shares issued and 284,992,650 shares outstanding at June 30, 2022 and 294,260,623 shares issued and 284,696,972 shares outstanding at December 31, 2021	30		29
Additional paid-in capital	Additional paid-in capital	3,007,696		3,004,433		Additional paid-in capital	3,024,236		3,013,017
Retained earnings (accumulated deficit)	Retained earnings (accumulated deficit)	(423,077)		(400,501)		Retained earnings (accumulated deficit)	(54,698)		(262,326)
Total shareholders’ equity		2,584,648		2,603,961
Noncontrolling interest		—		—
Total equity		2,584,648		2,603,961
TOTAL LIABILITIES AND EQUITY		$	3,882,341	$	3,827,425
Total Shareholders' equity						Total Shareholders' equity	2,969,568		2,750,720
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY						TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	4,224,030	$	3,804,594

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

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Operating revenues	Operating revenues									Operating revenues
Oil and gas sales	Oil and gas sales	$	288,505	$	149,101	$	713,473	$	432,379	Oil and gas sales	$	472,654	$	232,577	$	819,931	$	424,968
Operating expenses	Operating expenses									Operating expenses
Lease operating expenses	Lease operating expenses	28,685		24,543		77,522		83,021		Lease operating expenses	28,900		22,976		57,634		48,837
Severance and ad valorem taxes	Severance and ad valorem taxes	17,800		7,839		46,167		30,108		Severance and ad valorem taxes	34,695		15,784		59,746		28,367
Gathering, processing and transportation expenses	Gathering, processing and transportation expenses	24,164		19,130		64,283		53,353		Gathering, processing and transportation expenses	25,756		19,494		47,647		40,119
Depreciation, depletion and amortization	Depreciation, depletion and amortization	76,047		89,444		213,259		283,722		Depreciation, depletion and amortization	82,117		73,429		153,126		137,212
General and administrative expenses										General and administrative expenses	9,947		28,807		40,550		54,063
Merger and integration expense										Merger and integration expense	5,685		—		5,685		—
Impairment and abandonment expense	Impairment and abandonment expense	7,712		19,904		26,111		650,629		Impairment and abandonment expense	506		9,199		3,133		18,399
Exploration and other expenses	Exploration and other expenses	1,839		2,670		4,698		10,730		Exploration and other expenses	1,954		1,764		4,261		2,859
General and administrative expenses		35,748		17,582		89,811		54,446
Total operating expenses	Total operating expenses	191,995		181,112		521,851		1,166,009		Total operating expenses	189,560		171,453		371,782		329,856
Net gain (loss) on sale of long-lived assets	Net gain (loss) on sale of long-lived assets	(290)		145		(254)		388		Net gain (loss) on sale of long-lived assets	(1,406)		(8)		(1,324)		36
Proceeds from terminated sale of assets	Proceeds from terminated sale of assets	—		—		5,983		—		Proceeds from terminated sale of assets	—		5,983		—		5,983
Income (loss) from operations	Income (loss) from operations	96,220		(31,866)		197,351		(733,242)		Income (loss) from operations	281,688		67,099		446,825		101,131

Other income (expense)	Other income (expense)									Other income (expense)
Interest expense	Interest expense	(14,690)		(17,718)		(47,357)		(51,510)		Interest expense	(14,326)		(15,182)		(27,480)		(32,667)
Gain (loss) on extinguishment of debt	Gain (loss) on extinguishment of debt	—		—		(22,156)		143,443		Gain (loss) on extinguishment of debt	—		(22,156)		—		(22,156)
Net gain (loss) on derivative instruments	Net gain (loss) on derivative instruments	(44,527)		(1,968)		(150,685)		(40,330)		Net gain (loss) on derivative instruments	(34,134)		(54,959)		(163,657)		(106,158)
Other income (expense)	Other income (expense)	121		23		271		(29)		Other income (expense)	85		143		203		150
Total other income (expense)	Total other income (expense)	(59,096)		(19,663)		(219,927)		51,574		Total other income (expense)	(48,375)		(92,154)		(190,934)		(160,831)

Income (loss) before income taxes	Income (loss) before income taxes	37,124		(51,529)		(22,576)		(681,668)		Income (loss) before income taxes	233,313		(25,055)		255,891		(59,700)
Income tax (expense) benefit	Income tax (expense) benefit	—		—		—		85,124		Income tax (expense) benefit	(41,487)		—		(48,263)		—
Net income (loss)	Net income (loss)	37,124		(51,529)		(22,576)		(596,544)		Net income (loss)	$	191,826	$	(25,055)	$	207,628	$	(59,700)
Less: Net (income) loss attributable to noncontrolling interest		—		—		—		2,362
Net income (loss) attributable to Class A Common Stock		$	37,124	$	(51,529)	$	(22,576)	$	(594,182)

Income (loss) per share of Class A Common Stock:
Income (loss) per share of Common Stock:										Income (loss) per share of Common Stock:
Basic	Basic	$	0.13	$	(0.19)	$	(0.08)	$	(2.14)	Basic	$	0.67	$	(0.09)	$	0.73	$	(0.21)
Diluted	Diluted	$	0.12	$	(0.19)	$	(0.08)	$	(2.14)	Diluted	$	0.60	$	(0.09)	$	0.66	$	(0.21)

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

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

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


		Nine Months Ended September 30,					Six Months Ended June 30,
		2021		2020			2022		2021
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net income (loss)	Net income (loss)	$	(22,576)	$	(596,544)	Net income (loss)	$	207,628	$	(59,700)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	Adjustments to reconcile net income (loss) to net cash provided by operating activities:					Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	Depreciation, depletion and amortization	213,259		283,722		Depreciation, depletion and amortization	153,126		137,212
Stock-based compensation expense - equity awards	Stock-based compensation expense - equity awards	32,299		16,164		Stock-based compensation expense - equity awards	12,202		9,066
Stock-based compensation expense - liability awards	Stock-based compensation expense - liability awards	19,950		—		Stock-based compensation expense - liability awards	5,127		25,074
Impairment and abandonment expense	Impairment and abandonment expense	26,111		650,629		Impairment and abandonment expense	3,133		18,399
Deferred tax expense (benefit)	Deferred tax expense (benefit)	—		(85,124)		Deferred tax expense (benefit)	47,663		—
Net (gain) loss on sale of long-lived assets	Net (gain) loss on sale of long-lived assets	254		(388)		Net (gain) loss on sale of long-lived assets	1,324		(36)
Non-cash portion of derivative (gain) loss	Non-cash portion of derivative (gain) loss	61,490		(1,103)		Non-cash portion of derivative (gain) loss	47,131		45,759
Amortization of debt issuance costs and debt discount	Amortization of debt issuance costs and debt discount	3,935		4,112		Amortization of debt issuance costs and debt discount	4,226		2,886
(Gain) loss on extinguishment of debt	(Gain) loss on extinguishment of debt	22,156		(143,443)		(Gain) loss on extinguishment of debt	—		22,156
Changes in operating assets and liabilities:	Changes in operating assets and liabilities:					Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(Increase) decrease in accounts receivable	(42,998)		48,139		(Increase) decrease in accounts receivable	(62,751)		(33,483)
(Increase) decrease in prepaid and other assets	(Increase) decrease in prepaid and other assets	1,803		(2,825)		(Increase) decrease in prepaid and other assets	(6,201)		(9)
Increase (decrease) in accounts payable and other liabilities	Increase (decrease) in accounts payable and other liabilities	17,449		(43,107)		Increase (decrease) in accounts payable and other liabilities	42,491		12,301
Net cash provided by operating activities	Net cash provided by operating activities	333,132		130,232		Net cash provided by operating activities	455,099		179,625
Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Acquisition of oil and natural gas properties	Acquisition of oil and natural gas properties	(4,285)		(7,689)		Acquisition of oil and natural gas properties	(2,592)		(638)
Drilling and development capital expenditures	Drilling and development capital expenditures	(215,358)		(300,660)		Drilling and development capital expenditures	(224,011)		(126,665)
Purchases of other property and equipment	Purchases of other property and equipment	(686)		(1,035)		Purchases of other property and equipment	(2,863)		(471)
Proceeds from sales of oil and natural gas properties	Proceeds from sales of oil and natural gas properties	4,011		1,375		Proceeds from sales of oil and natural gas properties	863		698
Net cash used in investing activities	Net cash used in investing activities	(216,318)		(308,009)		Net cash used in investing activities	(228,603)		(127,076)
Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:

Proceeds from borrowings under revolving credit facility	Proceeds from borrowings under revolving credit facility	450,000		490,000		Proceeds from borrowings under revolving credit facility	170,000		320,000
Repayment of borrowings under revolving credit facility	Repayment of borrowings under revolving credit facility	(575,000)		(310,000)		Repayment of borrowings under revolving credit facility	(195,000)		(395,000)
Proceeds from issuance of convertible senior notes		170,000		—
Proceeds from issuance of senior notes						Proceeds from issuance of senior notes	—		170,000
Debt issuance costs	Debt issuance costs	(6,421)		(6,650)		Debt issuance costs	(8,533)		(6,421)
Premiums paid on capped call transactions	Premiums paid on capped call transactions	(14,688)		—		Premiums paid on capped call transactions	—		(14,688)
Redemption of senior secured notes	Redemption of senior secured notes	(127,073)		—		Redemption of senior secured notes	—		(127,073)
Proceeds from exercise of stock options	Proceeds from exercise of stock options	15		—		Proceeds from exercise of stock options	8		15
Restricted stock used for tax withholdings	Restricted stock used for tax withholdings	(14,459)		(598)		Restricted stock used for tax withholdings	(1,259)		(477)
Net cash (used in) provided by financing activities		(117,626)		172,752
Net cash used in financing activities						Net cash used in financing activities	(34,784)		(53,644)
Net increase (decrease) in cash, cash equivalents and restricted cash	Net increase (decrease) in cash, cash equivalents and restricted cash	(812)		(5,025)		Net increase (decrease) in cash, cash equivalents and restricted cash	191,712		(1,095)
Cash, cash equivalents and restricted cash, beginning of period	Cash, cash equivalents and restricted cash, beginning of period	8,339		15,543		Cash, cash equivalents and restricted cash, beginning of period	9,935		8,339
Cash, cash equivalents and restricted cash, end of period	Cash, cash equivalents and restricted cash, end of period	$	7,527	$	10,518	Cash, cash equivalents and restricted cash, end of period	$	201,647	$	7,244

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

Table of Contents

CENTENNIAL RESOURCE DEVELOPMENT, INC.

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


		Nine Months Ended September 30,					Six Months Ended June 30,
		2021		2020			2022		2021
Supplemental cash flow information	Supplemental cash flow information					Supplemental cash flow information
Cash paid for interest	Cash paid for interest	$	40,548	$	48,331	Cash paid for interest	$	24,276	$	30,124

Cash paid for income taxes						Cash paid for income taxes	600		—
Supplemental non-cash activity	Supplemental non-cash activity					Supplemental non-cash activity
Accrued capital expenditures included in accounts payable and accrued expenses	Accrued capital expenditures included in accounts payable and accrued expenses	$	44,591	$	13,593	Accrued capital expenditures included in accounts payable and accrued expenses	$	63,486	$	53,096
Asset retirement obligations incurred, including revisions to estimates	Asset retirement obligations incurred, including revisions to estimates	110		579		Asset retirement obligations incurred, including revisions to estimates	389		66
Change in Senior Notes from debt exchange
Senior Secured Notes issued in the debt exchange, net of debt discount		—		106,030
2026 Senior Notes extinguished in the debt exchange, net of unamortized debt issue costs		—		(108,632)
2027 Senior Notes extinguished in the debt exchange, net of unamortized discount and debt issue costs		—		(140,840)

Reconciliation of cash, cash equivalents and restricted cash presented on the consolidated statements of cash flows for the periods presented:


		Nine Months Ended September 30,					Six Months Ended June 30,
		2021		2020			2022		2021
Cash and cash equivalents	Cash and cash equivalents	$	4,985	$	5,177	Cash and cash equivalents	$	201,092	$	4,702
Restricted cash(1)	Restricted cash(1)	2,542		5,341		Restricted cash(1)	555		2,542
Total cash, cash equivalents and restricted cash	Total cash, cash equivalents and restricted cash	$	7,527	$	10,518	Total cash, cash equivalents and restricted cash	$	201,647	$	7,244

(1) Included in Prepaid and other current assets ~~and~~ ~~Other noncurrent assets~~ ~~line items~~ in the consolidated balance ~~sheets.~~

sheet as of June 30, 2022.

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

Table of Contents

CENTENNIAL RESOURCE DEVELOPMENT, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)

(in thousands)


																					Common Stock					Additional Paid-In Capital				Retained Earnings (Accumulated Deficit)				Total Shareholders’ Equity
																					Shares			Amount
Balance at December 31, 2021																			Balance at December 31, 2021		294,261			$	29			$	3,013,017			$	(262,326)			$	2,750,720
Restricted stock issued																			Restricted stock issued		20			—		—				—				—
Restricted stock forfeited																			Restricted stock forfeited		(52)			—		—				—				—
Restricted stock used for tax withholding																			Restricted stock used for tax withholding		(150)			—		(1,259)				—				(1,259)
Stock option exercises																			Stock option exercises		3			—		1				—				1
Issuance of Common Stock under Employee Stock Purchase Plan																			Issuance of Common Stock under Employee Stock Purchase Plan		53			—		268				—				268
Stock-based compensation - equity awards																			Stock-based compensation - equity awards		—			—		5,545				—				5,545
Net income (loss)																			Net income (loss)		—			—		—				15,802				15,802
Balance at March 31, 2022																			Balance at March 31, 2022		294,135			29		3,017,572				(246,524)				2,771,077
Restricted stock issued																			Restricted stock issued		2,998			1		—				—				1
Restricted stock forfeited																			Restricted stock forfeited		(75)			—		—				—				—
Stock option exercises																			Stock option exercises		2			—		7				—				7
Stock-based compensation - equity awards																			Stock-based compensation - equity awards		—			—		6,657				—				6,657
Net income (loss)																			Net income (loss)		—			—		—				191,826				191,826
Balance at June 30, 2022																			Balance at June 30, 2022		297,060			30		$	3,024,236			$	(54,698)			$	2,969,568

	Common Stock
	Class A			Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)				Total Shareholders’ Equity		Non-controlling Interest		Total Equity
	Shares	Amount
Balance at December 31, 2020	290,646	$	29				$	3,004,433			$	(400,501)			$	2,603,961			$	—		$	2,603,961

Restricted stock forfeited	(1)	—			—				—		—		—				—
Restricted stock used for tax withholding	(128)	—			(477)				—		(477)		—				(477)
Issuance of Class A common stock under Employee Stock Purchase Plan	276	—			167				—		167		—				167
Stock-based compensation - equity awards	—	—			4,585				—		4,585		—				4,585
Capped call premiums	—	—			(14,688)				—		(14,688)		—				(14,688)
Net income (loss)	—	—			—				(34,645)		(34,645)		—				(34,645)
Balance at March 31, 2021	290,793	29			2,994,020				(435,146)		2,558,903		—				2,558,903

Restricted stock forfeited	(7)	—			—				—		—		—				—

Stock option exercises	15	—			15				—		15		—				15
Stock-based compensation - equity awards	—	—			4,481				—		4,481		—				4,481

Net income (loss)	—	—			—				(25,055)		(25,055)		—				(25,055)
Balance at June 30, 2021	290,801	29			2,998,516				(460,201)		2,538,344		—				2,538,344
Restricted stock issued	6,075	—			—				—		—		—				—
Restricted stock forfeited	(4)	—			—				—		—		—				—
Stock option exercises	1	—			—				—		—		—				—
Restricted stock used for tax withholding	(2,763)	—			(13,982)				—		(13,982)		—				(13,982)
Issuance of Class A common stock under Employee Stock Purchase Plan	170	—			(71)				—		(71)		—				(71)
Stock-based compensation - equity awards	—	—			23,233				—		23,233		—				23,233
Net income (loss)	—	—			—				37,124		37,124		—				37,124
Balance at September 30, 2021	294,280	$	29		$	3,007,696			$	(423,077)	$	2,584,648	$	—			$	2,584,648

~~Table of Contents~~

~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

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

~~(in thousands)~~


		Common Stock
		Class A			Class C			Additional Paid-In Capital				Retained Earnings (Accumulated Deficit)		Total Shareholders’ Equity		Non-controlling Interest				Total Equity
		Shares	Amount		Shares	Amount
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		1,305	—		—	—		—				—		—		—				—
Balance at December 31, 2020																						Balance at December 31, 2020	290,646			$	29		$	3,004,433	$	(400,501)	$	2,603,961
Restricted stock forfeited	Restricted stock forfeited	(406)	—		—	—		—				—		—		—				—		Restricted stock forfeited	(1)			—			—		—		—
Restricted stock used for tax withholding	Restricted stock used for tax withholding	(78)	—		—	—		(208)				—		(208)		—				(208)		Restricted stock used for tax withholding	(128)			—			(477)		—		(477)
Issuance of Class A common stock under Employee Stock Purchase Plan		59	—		—	—		230				—		230		—				230
Issuance of Common Stock under Employee Stock Purchase Plan																						Issuance of Common Stock under Employee Stock Purchase Plan	276			—			167		—		167
Stock-based compensation - equity awards																						Stock-based compensation - equity awards	—			—			4,585		—		4,585
Capped call premiums																						Capped call premiums	—			—			(14,688)		—		(14,688)
Net income (loss)																						Net income (loss)	—			—			—		(34,645)		(34,645)
Balance at March 31, 2021																						Balance at March 31, 2021	290,793			29			2,994,020		(435,146)		2,558,903
Restricted stock forfeited																						Restricted stock forfeited	(7)			—			—		—		—
Stock option exercises																						Stock option exercises	15			—			15		—		15
Stock-based compensation - equity awards	Stock-based compensation - equity awards	—	—		—	—		6,409				—		6,409		—				6,409		Stock-based compensation - equity awards	—			—			4,481		—		4,481
Net income (loss)	Net income (loss)	—	—		—	—		—				(547,983)		(547,983)		(2,362)				(550,345)		Net income (loss)	—			—			—		(25,055)		(25,055)
Balance at March 31, 2020		281,530	28		1,034	—		2,982,187				(265,647)		2,716,568		10,219				2,726,787
Restricted stock issued		80	—		—	—		—				—		—		—				—
Restricted stock forfeited		(352)	—		—	—		—				—		—		—				—
Restricted stock used for tax withholding		(83)	—		—	—		(93)				—		(93)		—				(93)
Balance at June 30, 2021																						Balance at June 30, 2021	290,801			29			$	2,998,516	$	(460,201)	$	2,538,344

Stock-based compensation - equity awards		—	—		—	—		4,727				—		4,727		—				4,727
Conversion of common stock from Class C to Class A, net of tax		1,034	—		(1,034)	—		8,011				—		8,011		(10,219)				(2,208)
Net income (loss)		—	—		—	—		—				5,330		5,330		—				5,330
Balance at June 30, 2020		282,209	28		—	—		2,994,832				(260,317)		2,734,543		—				2,734,543

Restricted stock issued		8,272	1		—	—		(1)				—		—		—				—
Restricted stock forfeited		(104)	—		—	—		—				—		—		—				—
Restricted stock used for tax withholding		(377)	—		—	—		(297)				—		(297)		—				(297)
Issuance of Class A common stock under Employee Stock Purchase Plan		104	—		—	—		78				—		78		—				78
Stock-based compensation		—	—		—	—		5,028				—		5,028		—				5,028
Net income (loss)		—	—		—	—		—				(51,529)		(51,529)		—				(51,529)
Balance at September 30, 2020		290,104	$	29	—	$	—	$	2,999,640			$	(311,846)	$	2,687,823	$	—			$	2,687,823

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

1211

Table of Contents

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~~crude 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 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, ~~2020~~2021 (the ~~“2020~~“2021 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 ~~2020~~2021 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 subsidiary CRP, and CRP’s wholly-owned subsidiaries. Noncontrolling interest represents third-party ownership in CRP and is presented as a component of equity. As of March 31, 2020 the noncontrolling interest ownership of CRP was 0.4% but was subsequently reduced to zero as all remaining CRP Common Units (and corresponding shares of the Company’s Class C common stock) were converted into shares of the Company’s Class A common stock (the “Common Stock”) and CRP has since been a wholly-owned subsidiary of Centennial.

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. Additionally, the prices received for oil, natural gas and NGL production can heavily influence the Company’s assumptions, judgments and estimates and continued volatility of oil and gas prices could have a significant impact on the Company’s estimates.

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 for 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) derivative valuations; (x) deferred income taxes; and (xi) determining the fair values of certain stock-based compensation awards.

Leases

The Company has operating leases for drilling rig contracts, office rental agreements, and other wellhead equipment. During the second quarter of 2022, the Company extended two drilling rig contracts each for a two-year period. A lease right-of-use (ROU) asset and related liability have been recorded based on the present value of the future lease payments over the lease term of the drilling rigs. As of June 30, 2022, $19.0 million was recorded to current operating lease liability and $21.6 million was recorded to noncurrent operating lease liability related to these rigs. There have been no other significant changes in operating leases during the six months ended June 30, 2022. Refer to Note 15—Leases footnote in the notes to the consolidated financial statements in Item 8 of the Company’s 2021 Annual Report.

Table of Contents

CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Income Taxes

Income tax expense recognized 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.

~~Table of Contents~~

~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

The Company has 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 was recognized, which caused the Company’s provision for income taxes for each of the three and nine months periods ended September 30, 2021 and 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.

~~Recently Issued or Adopted Accounting Standards~~

~~In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-06,~~ ~~Debt—Debt with Conversion and Other Options and Derivatives and Hedging— Contracts in Entity’s Own Equity~~ ~~(“ASU 2020-06”)~~, ~~which updates the accounting requirements for convertible debt instruments and contracts in an entity’s own equity under FASB’s Accounting Standard Codification (“ASC”) Topic 470,~~ ~~Debt, ASC Topic 815,~~ ~~Derivatives and Hedging,~~ and applicable earnings-per-share guidance. The amendments in ASU 2020-06 are intended to simplify the accounting for convertible instruments by removing certain separation models in the existing debt guidance allowing convertible debt to be recorded as a single liability measured at its amortized cost. Additionally, the amendments remove certain conditions and clarify the scope of and certain requirements pertaining to derivative scope exception evaluations over such contracts and instruments. ASU 2020-06 requires retrospective application and is effective for public entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years, with early adoption permitted after December 15, 2020. The Company has adopted this guidance as of January 1, 2021, and there was no impact on previously reported amounts as a result of the adoption. Refer to ~~Note 4—Long-Term Debt~~ ~~for additional information regarding its convertible debt instruments.~~

Note 2—~~Property Divestiture~~Business Combination

Pending Merger with Colgate

On ~~February 24, 2020,~~May 19, 2022, the Company entered into a ~~purchase~~Business Combination Agreement (the “Business Combination Agreement”) with CRP, Colgate Energy Partners III, LLC (“Colgate”), and ~~sale agreement~~Colgate Energy Partners III MidCo, LLC (the ~~“Agreement”~~“Colgate Unitholder”) which provides for the combination of CRP and Colgate in a merger of equals transaction (the “Merger”), with CRP surviving the Merger (the “Surviving Company”) as a subsidiary of Centennial.

Colgate is an independent oil and gas company focused on the acquisition, development, exploration and production of oil and natural gas properties in the Delaware Basin. Colgate owns approximately 105,000 net leasehold acres and 25,000 net royalty acres in Reeves and Ward counties in Texas and Eddy County in New Mexico.

At the effective time of the Merger, all membership interests in CRP issued and outstanding will be converted into units in the Surviving Company (“Surviving Company Units”) equal to ~~sell certain~~the number of shares of Centennial’s Class A common stock (the “Common Stock”) that are outstanding at such time, and all of the Colgate Unitholder’s membership interest in Colgate will be exchanged for 269,300,000 shares of Class C common stock (with underlying Surviving Company Units) and $525 million in cash. The shares of Class C Common Stock to be issued to the Colgate Unitholders pursuant to the Business Combination Agreement will represent a noncontrolling interest in the Surviving Company.

The transaction has been unanimously approved by the Boards of Directors of both companies. The Company has filed its ~~water disposal assets.~~ ~~On May 15, 2020,~~definitive proxy statement with the ~~Agreement was terminated~~ SEC and the shareholder meeting is scheduled for August 29, 2022, where the Merger will be voted on by the Company’s shareholders. The Merger is expected to close shortly after the ~~transaction failed~~shareholder meeting subject to ~~close by the outside date set forth in the Agreement.~~

~~The purchaser deposited $10.0 million of cash in an escrow account~~ ~~(the “Deposit”) which, in the event of termination, was to be distributed to the Company or the purchaser in accordance with~~ ~~the remedy provisions~~customary closing conditions, including, among others, receipt of the ~~Agreement.~~ ~~In May 2021, a settlement between~~required approvals from the ~~Company and the purchaser was reached resulting in a partial distribution of the deposit to Centennial, which was included net of associated legal fees~~ ~~in the consolidated statements of operations.~~Company’s shareholders.

Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses

Accounts receivable are comprised of the following:


(in thousands)	(in thousands)	September 30, 2021		December 31, 2020		(in thousands)	June 30, 2022		December 31, 2021
Accrued oil and gas sales receivable, net	Accrued oil and gas sales receivable, net	$	82,120	$	41,670	Accrued oil and gas sales receivable, net	$	114,168	$	57,287
Joint interest billings, net	Joint interest billings, net	16,078		12,770		Joint interest billings, net	26,051		12,449
Other	Other	1,653		117		Other	1,379		1,559
Accounts receivable, net	Accounts receivable, net	$	99,851	$	54,557	Accounts receivable, net	$	141,598	$	71,295

Accounts payable and accrued expenses are comprised of the following:


(in thousands)	(in thousands)	September 30, 2021		December 31, 2020		(in thousands)	June 30, 2022		December 31, 2021
Accounts payable	Accounts payable	$	26,305	$	5,052	Accounts payable	$	31,134	$	9,736
Accrued capital expenditures	Accrued capital expenditures	29,033		21,471		Accrued capital expenditures	49,791		24,377
Revenues payable	Revenues payable	42,060		42,115		Revenues payable	60,541		40,438
Accrued employee compensation and benefits						Accrued employee compensation and benefits	9,038		17,218
Accrued interest	Accrued interest	19,233		15,138		Accrued interest	15,423		15,259
Accrued derivative settlements payable	Accrued derivative settlements payable	8,996		3,488		Accrued derivative settlements payable	21,168		8,591
Accrued employee compensation and benefits		11,192		11,516
Accrued expenses and other	Accrued expenses and other	13,792		11,659		Accrued expenses and other	21,127		14,637
Accounts payable and accrued expenses	Accounts payable and accrued expenses	$	150,611	$	110,439	Accounts payable and accrued expenses	$	208,222	$	130,256

1413

Table of Contents

CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 4—Long-Term Debt

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


(in thousands)	(in thousands)	September 30, 2021		December 31, 2020		(in thousands)	June 30, 2022		December 31, 2021
Credit Facility due 2023		$	205,000	$	330,000
Credit Facility due 2027						Credit Facility due 2027	$	—	$	25,000

Senior Notes	Senior Notes					Senior Notes
8.00% Senior Secured Notes due 2025		—		127,073
5.375% Senior Notes due 2026	5.375% Senior Notes due 2026	289,448		289,448		5.375% Senior Notes due 2026	289,448		289,448
6.875% Senior Notes due 2027	6.875% Senior Notes due 2027	356,351		356,351		6.875% Senior Notes due 2027	356,351		356,351
3.25% Convertible Senior Notes due 2028	3.25% Convertible Senior Notes due 2028	170,000		—		3.25% Convertible Senior Notes due 2028	170,000		170,000
Unamortized debt issuance costs on Senior Notes	Unamortized debt issuance costs on Senior Notes	(13,831)		(12,790)		Unamortized debt issuance costs on Senior Notes	(12,152)		(13,279)
Unamortized debt discount	Unamortized debt discount	(2,031)		(21,458)		Unamortized debt discount	(1,798)		(1,955)
Senior Notes, net	Senior Notes, net	799,937		738,624		Senior Notes, net	801,849		800,565

Total long-term debt, net	Total long-term debt, net	$	1,004,937	$	1,068,624	Total long-term debt, net	$	801,849	$	825,565

Credit Agreement

On February 18, 2022, CRP, the Company’s consolidated subsidiary, ~~has a~~entered into an amended and restated five-year secured credit ~~agreement~~facility (the “Credit Agreement”) with a syndicate of banks, ~~that provides for a five-year secured revolving~~which replaced our previous credit facility ~~maturing on~~that was set to mature in May ~~4, 2023 (the “Credit Agreement”).~~of 2023. The Credit Agreement increased our elected commitments to $750 million, increased our borrowing base to $1.15 billion and extended the maturity of the Credit Agreement to February 2027. As of ~~September~~June 30, ~~2021,~~2022, the Company had ~~$205.0 million in~~no borrowings outstanding and ~~$488.5~~$744.2 million in available borrowing capacity, which was net of ~~$6.5~~$5.8 million in letters of credit outstanding. From May of 2020 until April of 2021, the borrowing base had been reduced by an availability blocker of $31.8 million tied to the Senior Secured Notes. However, this availability blocker was eliminated as a result of the Senior Secured Notes redemption defined and discussed below.outstanding, under its new facility.

The amount available to be borrowed under ~~CRP’s~~the Credit Agreement is equal to the lesser of (i) the borrowing base, (ii) aggregate elected commitments, which ~~are currently~~is set at ~~$700.0~~$750 million, 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.~~in between the scheduled redeterminations. The borrowing base depends on, among other things, the quantities of CRP’s proved oil and natural gas reserves, estimated cash flows from ~~these~~those reserves, and the Company’s commodity hedge positions. Upon a redetermination of the borrowing base, if actual borrowings outstanding exceed the revised borrowing capacity, CRP could be required to immediately repay a portion of its debt outstanding. Borrowings under the Credit Agreement are guaranteed by certain of CRP’s subsidiaries and the Company. ~~In connection with the Credit Agreement’s fall 2021 semi-annual borrowing base redetermination, the borrowing base and amount of elected commitments were reaffirmed at $700.0 million.~~

Borrowings under the Credit Agreement may be base rate loans or ~~LIBOR~~Secured Overnight Financing Rate (“SOFR”) loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for ~~LIBOR~~SOFR loans. ~~LIBOR~~SOFR loans bear interest at ~~LIBOR (adjusted for statutory reserve requirements and subject to 1% floor)~~SOFR plus an applicable margin ~~which ranged~~ranging from ~~200~~225 to ~~300~~325 basis points, ~~as of September 30, 2021,~~ depending on the percentage of ~~the borrowing base utilized.~~elected commitments utilized, plus an additional 10 basis point credit spread adjustment. 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~~Term SOFR rate for a one-month interest period plus 100 basis points, plus an applicable margin, ~~which ranged~~ranging from ~~100~~125 to ~~200~~225 basis points, ~~as of September 30, 2021,~~ depending on the percentage of the borrowing base utilized. CRP also pays a commitment fee of 37.5 to 50 basis points on unused elected commitment amounts under its facility.

~~CRP’s~~The Credit Agreement provides for, among other things, the ability to repurchase outstanding shares of the Company’s Common Stock and junior debt, subject to certain leverage and elected commitment availability conditions and subject to the requirement that such repurchases are funded from our free cash flow. The Credit Agreement contains restrictive covenants that limit ~~its~~our ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or ~~declare dividends; (v)~~redeem junior debt; (vi) enter into commodity hedges exceeding a specified percentage of ~~the Company’s~~our expected production; ~~(vi)~~(vii) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; ~~(vii)~~(viii) incur liens; ~~(viii)~~(ix) sell assets; and ~~(ix)~~(x) engage in transactions with affiliates.

~~CRP’s~~The Credit Agreement also requires itCRP to maintain compliance with the following financial ratios:

(i) a current ratio, which is the ratio of CRP’s consolidated current assets (including an add back of unused commitments under ~~its~~the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding ~~any~~the current portion of long-term debt ~~due~~ under the Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(ii) a ~~first lien~~ leverage ratio, as defined within the Credit Agreement as the ratio of first lien debt to EBITDAX for the rolling four fiscal quarter period, which may not exceed 2.75 to 1.00 beginning with the quarter ending June 30, 2020 and extending through the quarter ending December 31, 2021, after which the maximum ratio shall decrease to 2.50 to 1.00 for each of the quarters ending in 2022; and

~~(iii) a leverage ratio, as also defined in~~ the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the ~~rolling~~prior four fiscal quarter period. Pursuant to amendments to the Credit Facility, the leverage ratio was suspended until March 31, 2022, at which time, the ratio may not exceed 5.0 to 1.0, with such maximum ratio declining at a ratequarters, of ~~0.25 for each succeeding quarter until March 31, 2023 when the ratio is set at~~ not greater than ~~4.0~~3.5 to 1.0.

CRP was in compliance with the covenants and the applicable financial ratios described above as of ~~September~~June 30, ~~2021 and through~~2022. In July 2022 in connection with the ~~filing of this Quarterly Report.~~pending Merger, CRP amended its Credit Agreement; refer to Note 14—Subsequent Events for additional information.

Convertible Senior Notes

On March 19, 2021, CRP issued $150.0 million in aggregate principal amount of 3.25% senior unsecured convertible notes due 2028 (the “Convertible Senior Notes”). On March 26, 2021, CRP issued an additional $20.0 million of Convertible Senior Notes pursuant to the exercise of the underwriters’ over-allotment option to purchase additional Convertible Senior Notes. These issuances resulted in aggregate net proceeds to CRP of $163.6 million, after deducting debt issuance costs of $6.4 million. Interest is payable on the Convertible Senior Notes semi-annually in arrears on each April 1 and October 1, commencing on October 1, 2021.

The Convertible Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP’s current subsidiaries.

The Convertible Senior Notes will mature on April 1, 2028 unless earlier repurchased, redeemed or converted. Before January 3, 2028, noteholders have the right to convert their Convertible Senior Notes (i) upon the occurrence of certain events, (ii) if the Company’s share price exceeds 130% of the conversion price for any 20 trading days during the last 30 consecutive trading days of a calendar quarter, after June 30, 2021, or (iii) if the trading price per $1,000 principal amount of the notes is less than 98% of the Company’s share price multiplied by the conversion rate, for a 10 consecutive trading day period. In addition, after January 2, 2028, noteholders may convert their Convertible Senior Notes at any time at their election through the second scheduled trading day immediately before the April 1, 2028 maturity date.

CRP can settle conversions by paying or delivering, as applicable, cash, shares of Common Stock, or a combination of cash and shares of Common Stock, at CRP’s election. The initial conversion rate is 159.2610 shares of Common Stock per $1,000 principal amount of Convertible Senior Notes, which represents an initial conversion price of approximately $6.28 per share of Common Stock. The conversion rate and conversion price are subject to customary adjustments upon the occurrence of certain events (as defined in the indenture) which, in certain circumstances, will increase the conversion rate for a specified period of time. In the context of this issuance, we refer to the notes as convertible in accordance with ASC 470 - Debt. However, per the terms of the Convertible Senior Notes’ indenture, the Convertible Senior Notes were issued by CRP and are exchangeable into shares of Centennial Resource Development, Inc.’s Common Stock.

CRP has the option to redeem, in whole or in part, all of the Convertible Senior Notes at any time on or after April 7, 2025, at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest to the date of redemption, but only if the last reported sale price per share of Common Stock exceeds 130% of the conversion price (i) for any 20 trading days during the 30 consecutive trading days ending on the day immediately before the date CRP sends the related redemption notice; and (ii) also on the trading day immediately before the date CRP sends such notice.

If certain corporate events occur, including certain business combination transactions involving the Company or CRP or a stock de-listing with respect to the Common Stock, noteholders may require CRP to repurchase their Convertible Senior Notes at a cash repurchase price equal to the principal amount of the Convertible Senior Notes to be repurchased, plus accrued and unpaid interest to the repurchase date.

Upon an Event of Default (as defined in the indenture governing the Convertible Senior Notes), the trustee or the holders of at least 25% of the aggregate principal amount of then outstanding Convertible Senior Notes may declare the Convertible Senior Notes immediately due and payable. In addition, a default resulting from certain events of bankruptcy or insolvency with respect to the Company, CRP or any of the subsidiary guarantors will automatically cause all outstanding Convertible Senior Notes to become due and payable.

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

At issuance, the Company recorded a liability equal to the face value the Convertible Senior Notes, net of unamortized debt issuance costs in the line items Long-term debt, net in the consolidated balance sheets. As of ~~September~~June 30, ~~2021,~~2022, the net liability recorded related to the Convertible Senior Notes was ~~$164.0~~$164.6 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Capped Called Transactions

In connection with the issuance of the Convertible Senior Notes in March 2021, CRP entered into privately negotiated capped call spread transactions with option counterparties (the “Capped Call Transactions”). The Capped Call Transactions cover the aggregate number of shares of Common Stock that initially underlie the Convertible Senior Notes and are expected to (i) generally reduce potential dilution to the Common Stock upon a conversion of the Convertible Senior Notes, and/or (ii) offset any cash payments CRP is required to make in excess of the principal amount of the Convertible Senior Notes, subject to a cap. The Capped Call Transactions have an initial strike price of $6.28 per share of Common Stock and an initial capped price of $8.4525 per share of Common Stock, each of which are subject to certain customary adjustments upon the occurrence of certain corporate events, as defined in the capped call agreements.

The cost of the Capped Call Transactions was $14.7 million, which was funded from proceeds from the Convertible Senior Note issuance. The cost to purchase the Capped Call Transactions was recorded to additional paid-in capital in the consolidated balances sheets and will not be subject to remeasurement each reporting period.

Senior Unsecured Notes ~~Debt Exchange~~

On ~~May 22, 2020~~, CRP completed its private exchange of debt pursuant to which a $254.2 million aggregate principal amount of Senior Unsecured Notes (defined below) was validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount (the “Debt Exchange”) of newly issued 8.00% second lien senior secured notes due 2025 (the “Senior Secured Notes”). The Company’s Debt Exchange was accounted for as an extinguishment of debt in accordance with ASC Topic 470-50, ~~Modifications and Extinguishments~~. As a result, a gain on the exchange of debt of $143.4 million was recognized in the consolidated statement of operations during the second quarter of 2020, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the new Senior Secured Notes issued, net of their associated debt discount of ~~$21.0 million,~~ ~~which was based on the Senior Secured Notes’ estimated fair value on the exchange date.~~

~~Senior Secured Notes~~

~~In connection with the Debt Exchange, on May 22, 2020, the Company issued~~ ~~$127.1 million~~ aggregate principal amount of Senior Secured Notes. The Senior Secured Notes were recorded at their fair value on the date of issuance equal to 83.44% of par (a debt discount of $21.0 million) and net of their associated debt issuance costs of $4.2 million.

~~In April 2021, the Company redeemed at par all of its $127.1 million~~ ~~aggregate principal amount of Senior Secured Notes,~~ ~~which was the intended use of proceeds from the Convertible Senior Notes offering~~. The Company paid accrued interest of $3.8 million and recorded a loss on debt extinguishment of $22.2 million related to the write-off of all unamortized debt issuance costs and discount amounts associated with the Senior Secured Notes.

~~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, which commenced on October 1, 2019. In May 2020 in connection with the Debt Exchange, $143.7 million aggregate principal amount of the 2027 Senior Notes was exchanged for Senior Secured Notes. As of September 30, 2021, the remaining aggregate principal amount of 2027 Senior Notes outstanding was $356.4 million.

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 Unsecured 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.

In May 2020, ~~in connection with the Debt Exchange,~~ $110.6 million aggregate principal amount of the 2026 Senior Notes ~~was~~and $143.7 million aggregate principal amount of the 2027 Senior Notes were validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount of 8.00% second lien senior secured notes, which were fully redeemed at par in connection with the Convertible Senior ~~Secured Notes.~~Notes issuance during the second quarter of 2021. As of ~~September~~June 30, ~~2021,~~2022, the remaining aggregate principal amount of 2027 Senior Notes and 2026 Senior Notes outstanding was $356.4 million and $289.4 ~~million.~~million, respectively.

The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP’s current subsidiaries that guarantee CRP’s ~~revolving credit facility.~~

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

Credit Agreement.

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 Unsecured 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 Unsecured 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 Unsecured 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 Unsecured Notes at a redemption price equal to 100% of the principal amount of the Senior Unsecured 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 Unsecured 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 Unsecured Notes may require CRP to repurchase all or a portion of its Senior Unsecured Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Unsecured Notes, plus any accrued but unpaid interest to the date of repurchase.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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~~June 30, ~~2021~~2022 and through the filing of this Quarterly Report.

Upon an Event of Default (as defined in the indentures governing the Senior Unsecured Notes), the trustee or the holders of at least 25% of the aggregate principal amount of then outstanding Senior Unsecured Notes may declare the Senior Unsecured 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 Unsecured Notes to become due and payable.

Note 5—Asset Retirement Obligations

The following table summarizes changes in the Company’s asset retirement obligations (“ARO”) associated with its working interests in oil and gas properties for the ~~nine~~six months ended ~~September~~June 30, ~~2021:~~2022:


(in thousands)
Asset retirement obligations, beginning of period	$	~~17,009~~17,240

Liabilities incurred	~~131~~481

Liabilities divested and settled	~~(351)~~(11)
Accretion expense	~~942~~533
Revisions to estimated cash flows	~~(21)~~(92)
Asset retirement obligations, end of period	$	~~17,710~~18,151

ARO reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and 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 estimates and assumptions, including 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 liabilities, 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 with an offsetting charge to accretion expense, which is included within depreciation, depletion and amortization.

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

Note 6—Stock-Based Compensation

On ~~October 7, 2016,~~April 27, 2022, the stockholders of the Company approved the second amended and restated Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the “LTIP”), ~~which authorized an aggregate of 16,500,000 shares of Common Stock for issuance to employees and directors. 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 Common Stock authorized for issuance ~~by 8,250,000~~to employees and directors from 24,750,000 shares to 44,250,000 shares. The LTIP provides for grants of restricted stock, stock options (including incentive stock options and nonqualified stock options), restricted stock units (including performance stock units), stock appreciation rights and other stock or cash-based awards.

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

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	(in thousands)	2021		2020		2021		2020		(in thousands)	2022		2021		2022		2021
Equity Awards	Equity Awards									Equity Awards
Restricted stock	Restricted stock	$	22,064	$	3,864	$	29,206	$	11,605	Restricted stock	$	4,481	$	3,536	$	7,920	$	7,142
Stock option awards	Stock option awards	159		399		664		1,674		Stock option awards	26		234		57		505
Performance stock units	Performance stock units	929		653		2,214		2,659		Performance stock units	2,079		646		4,082		1,285
Other stock-based compensation expense(1)	Other stock-based compensation expense(1)	81		112		215		226		Other stock-based compensation expense(1)	71		65		143		134
Total stock-based compensation - equity awards	Total stock-based compensation - equity awards	23,233		5,028		32,299		16,164		Total stock-based compensation - equity awards	6,657		4,481		12,202		9,066

Liability Awards	Liability Awards									Liability Awards
Restricted stock units	Restricted stock units	(3,563)		290		4,392		290		Restricted stock units	—		4,647		—		7,955
Performance stock units	Performance stock units	4,619		197		21,738		197		Performance stock units	(8,593)		10,013		5,127		17,119
Total stock-based compensation - liability awards	Total stock-based compensation - liability awards	1,056		487		26,130		487		Total stock-based compensation - liability awards	(8,593)		14,660		5,127		25,074

Total stock-based compensation expense	Total stock-based compensation expense	$	24,289	$	5,515	$	58,429	$	16,651	Total stock-based compensation expense	$	(1,936)	$	19,141	$	17,329	$	34,140

(1) Includes expenses related to the Company’s 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.

Equity Awards

The Company has restricted stock, stock options and performance stock units (“PSUs”) outstanding that were granted under the LTIP as discussed below. Each award has service-based and, in the case of the PSUs, market-based vesting requirements, and are expected to be settled in shares of Common Stock upon vesting. As a result, these awards are classified as equity-based awards in accordance with ASC Topic 718, Compensation-Stock Compensation (“ASC 718”).

Restricted Stock

The following table provides information about restricted stock activity during the ~~nine~~six months ended ~~September~~June 30, ~~2021:~~2022:


		Restricted Stock	Weighted Average Grant-Date Fair Value			Restricted Stock	Weighted Average Fair Value
Unvested balance as of December 31, 2020		12,093,723	$	2.33
Unvested balance as of December 31, 2021					Unvested balance as of December 31, 2021	10,143,687	$	2.85
Granted	Granted	3,091,222	5.25		Granted	2,409,749	7.90
Vested	Vested	(4,368,364)	3.21		Vested	(387,929)	5.03
Forfeited	Forfeited	(14,912)	7.07		Forfeited	(97,829)	5.40
Unvested balance as of September 30, 2021		10,801,669	2.80
Unvested balance as of June 30, 2022					Unvested balance as of June 30, 2022	12,067,678	3.76

The Company grants service-based restricted stock 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 these service-based restricted stock is based on the closing market price of the Company’s Common Stock on the grant date, and such costs are recognized ratably over the applicable vesting period. There were 3.1 million shares of restricted stock granted during the nine months ended September 30, 2021, including 0.6 million shares of restricted stock units that can be settled in either Common Stock or cash upon vesting at the Company’s discretion. The Company intends and has the ability to settle these restricted stock units in Common Stock upon vesting and has treated them as equity-based awards accordingly. The total fair value of restricted stock that vested

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

during the ~~nine~~six months ended ~~September~~June 30, 2022 and 2021 ~~and 2020~~ was ~~$14.0~~$2.0 million and ~~$16.1~~$2.7 million, respectively. Unrecognized compensation cost related to restricted shares that were unvested as of ~~September~~June 30, ~~2021~~2022 was ~~$26.1~~$32.4 million, which the Company expects to recognize over a weighted average period of ~~2.3~~2.5 years.

Stock Options

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

Table 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.Contents

The following table summarizes the assumptions and related information used to determine the grant-date fair value of stock option awards for the nine months ended September 30, 2020. No stock options were granted during the nine months ended September 30, 2021.CENTENNIAL RESOURCE DEVELOPMENT, INC.


			~~Nine Months Ended September 30, 2020~~
~~Weighted average grant-date fair value per share~~			~~$1.16~~
~~Expected term (in years)~~			6
~~Expected stock volatility~~			~~86%~~
~~Dividend yield~~			—%
~~Risk-free interest rate~~			~~1.0%~~

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table provides information about stock option awards outstanding during the ~~nine~~six months ended ~~September~~June 30, ~~2021:~~2022:


		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, 2020		2,363,334	$	15.07
Outstanding as of December 31, 2021								Outstanding as of December 31, 2021	2,212,798	$	15.31
Granted	Granted	—	—					Granted	—	—
Exercised	Exercised	(16,367)	0.93			$	80	Exercised	(4,000)	1.92			$	24
Forfeited	Forfeited	(13,836)	9.00					Forfeited	(2,500)	7.58
Expired	Expired	(60,499)	17.19					Expired	(60,832)	14.69
Outstanding as of September 30, 2021		2,272,632	15.15		5.71	$	453
Exercisable as of September 30, 2021		2,092,443	15.68		5.53	$	92

Outstanding as of June 30, 2022								Outstanding as of June 30, 2022	2,145,466	15.36		4.9	$	276
Exercisable as of June 30, 2022								Exercisable as of June 30, 2022	2,094,791	15.63		4.9	$	165

The total fair value of stock options that vested during the ~~nine~~six months ended ~~September~~June 30, 2022 and 2021 ~~and 2020~~ was ~~$0.8~~$0.2 million and ~~$4.7~~$0.5 million, respectively. The intrinsic value of the stock options exercised was minimal for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 and ~~2020.~~$0.1 million for the six months ended June 30, 2021. As of ~~September~~June 30, ~~2021,~~2022, there was ~~$0.2~~less than $0.1 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 period of ~~0.9~~0.6 years.

Performance Stock Units

The Company grants performance stock units (“PSU”) 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. These market-based conditions must be met in order for the stock awards to vest, and it is therefore possible that no shares could ultimately vest. However, the Company recognizes compensation expense for the ~~performance stock units~~PSUs subject to market conditions regardless of whether it becomes probable that these conditions will be met or not, and compensation expense is not reversed if vesting does not actually occur.

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

During the ~~nine~~six months ended ~~September~~June 30, 2022 and the year ended December 31, 2021 there were 0.7 million and 1.1 million shares, respectively, of performance stock units granted that can be settled in either Common Stock or cash upon vesting at the Company’s discretion. The Company currently intends to settle these performance stock units in Common Stock and has ~~treated them as equity-based awards accordingly. These performance stock units were legally granted to certain executive officers. At this time, however, the Company currently does not have~~ sufficient shares available under the LTIP to settle the units in Common Stock at the potential future vesting ~~date in the third quarter 2024. As a result,~~dates. Accordingly, these units have been treated as equity-based awards and a grant date ~~in accordance with ASC 718, has not yet been fully achieved,~~was established on April 27, 2022, which represents the date the 2022 awards were approved and the ~~awards’ fair value will be re-measured as of each balance sheet date. Stock compensation expense amounts recognized in future periods for these awards will vary until~~date sufficient shares ~~are~~become available under the LTIP ~~and all~~to settle 2021 awards in Common Stock. As a result, these PSU awards’ fair value was determined as of the grant date ~~criteria have been satisfied accordingly. The information included in the tables below reflects the fair~~and remeasurement of such value ~~of the performance stock units as of September 30, 2021.~~will not be required.

The 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 the Company’s 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 fair value of performance stock ~~units awarded during the periods presented:~~units:


			~~Nine Months Ended September 30, 2021~~
~~Weighted average fair value per share~~			~~$11.30~~
~~Number of simulations~~			~~10,000,000~~
~~Expected implied stock volatility~~			~~98.8%~~
~~Dividend yield~~			—%
~~Risk-free interest rate~~			~~0.5%~~


	2021 Awards	2022 Awards
Weighted average fair value per share	$12.79	$13.81
Number of simulations	10,000,000	10,000,000
Expected implied stock volatility	99.5%	96.3%
Dividend yield	—%	—%
Risk-free interest rate	2.3%	2.7%

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table provides information about performance stock units outstanding during the ~~nine~~six months ended ~~September~~June 30, ~~2021:~~

Awards Weighted Average Fair Value
Unvested balance as of December 31, 2020 679,281 $ 11.13
Granted 1,094,767 11.30
Vested — —
Cancelled (193,068) 22.35
Forfeited — —
Unvested balance as of September 30, 2021 1,580,980 9.88
2022:


	Awards	Weighted Average Fair Value
Unvested balance as of December 31, 2021	1,580,980	$	8.54
Granted	733,330	13.81
Vested	—	—
Cancelled	—	—
Forfeited	—	—
Unvested balance as of June 30, 2022	2,314,310	11.83

As of ~~September~~June 30, ~~2021,~~2022, there was ~~$12.5~~$19.1 million of unrecognized compensation cost related to ~~performance stock units~~PSUs that were unvested, which the Company expects to recognize on a pro-rata basis over a weighted average period of ~~2.7~~2.4 years.

Liability Awards

The Company has ~~restricted stock units and~~ performance stock units that were granted under the LTIP, which ~~will be settled~~are settleable in cash and are therefore classified as liability awards in accordance with ASC 718. The Company also had restricted stock units granted under the LTIP that were settleable in cash and that were classified as liability awards, but all such units were settled in their entirety during the third quarter of 2021. Compensation cost for ~~the~~these liability awards is based on the fair value of the units as of the balance sheet date as further discussed below, and such costs are recognized ratably over the service periods of the awards. As the fair value of liability awards is required to be re-measured each period end, stock compensation expense amounts recognized in future periods for these awards will vary. The estimated future cash payments ofassociated with these awards are presented as liabilities within Other long-term liabilities in the consolidated balances sheets.

Restricted Stock Units

The Company granted 5.5 million restricted stock units during the third quarter of 2020 to certain officers (non-NEOs) and employees that ~~are~~were settleable in cash upon vesting. The restricted stock units ~~vest~~vested annually in one-third increments over a three-year service period, with the first portion vesting on September 1, 2021. After one year from the grant date, however, the remaining two-thirds of unvested restricted stock units ~~can~~could vest immediately, on an accelerated basis, if they meet certain market-based vesting criteria equal to the maximum return percentage ~~discussed below~~ for at least 20 out of any 30 consecutive trading days. Additionally, the restricted stock units ~~include~~included maximum and minimum return amounts equal to 400% and 25%, respectively, of the closing market price of the Company’s Common Stock on the grant date.

~~Table~~During the second quarter of ~~Contents~~

~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~The~~2021, the Company amended these restricted stock unit agreements to (i) allow the units to be settleable in either cash or Common Stock upon vesting at the Company’s discretion and (ii) remove the maximum and minimum return amounts if the units are settled in Common Stock. The amended terms were effective July 1, 2021, and at ~~this~~that time, the Company intended to settle a portion of these restricted stock units in cash. As a result, the awards continued to be classified as liabilities in accordance with ASC 718.

During the third quarter of 2021, the maximum return event (described above) occurred resulting in an immediate vesting of all the outstanding restricted stock units on September 1, 2021. The Company settled 1.8 million of the restricted stock units in cash resulting in a $6.2 million cash payment, and the remaining units were settled in Common Stock. The portion of the units that were settled in Common Stock were recognized as equity instruments on the vesting date, which resulted in $13.6 million of incremental stock compensation expense being recognized during the ~~third quarter~~year ended December 31, 2021. There are no remaining restricted stock units outstanding as of ~~2021.~~June 30, 2022.

Performance Stock Units

The Company granted 5.5 million ~~performance stock units (“PSU”)~~PSUs during third quarter of 2020 to certain executive officers that will be settled in cash and are subject to market-based vesting criteria as well as a three-year service condition. 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 lessor percentage, than the average percentage increase or decrease, respectively, of the stock price of a peer group of companies. These market-based conditions must be met in order for the PSU awards to vest, and it is therefore possible that no units could ultimately vest and cumulative stock compensation expense recognized for these awards would then be reduced to zero. As of ~~September~~June 30, ~~2021,~~2022, there was ~~$35~~$15.2 million of unrecognized compensation cost that represents the unvested portion of the fair value of the PSUs at ~~September~~June 30, ~~2021~~2022 and will be recognized over a weighted average period of ~~1.8~~1.0 years.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Liability Awards Fair Value

The fair value of the ~~performance stock units~~PSUs was estimated using a Monte Carlo valuation model as of the balance sheet date. 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 the Company’s Common Stock as well as the peer companies that are specified in the PSU award agreement. The risk-free rate is based on U.S. Treasury yield curve rates with maturities consistent with the remaining vesting or performance period.

The following table summarizes the key assumptions and related information used to determine the fair value of the liability awards as of ~~September~~June 30, ~~2021:~~

2022:


						Performance stock units

Number of simulations						10,000,000
Expected implied stock volatility						~~70.1%~~73.7%
Dividend yield						—%
Risk-free interest rate						~~0.2%~~2.8%

Note 7—Derivative Instruments

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

Commodity Derivative Contracts

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

The following table summarizes the approximate volumes and average contract prices of derivative contracts the Company had in place as of June 30, 2022:


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Crude Price ($/Bbl)(1)
Crude oil swaps	July 2022 - September 2022	782,000	8,500	$65.46
	October 2022 - December 2022	690,000	7,500	65.63
	January 2023 - March 2023	225,000	2,500	73.51
	April 2023 - June 2023	227,500	2,500	73.25
	July 2023 - September 2023	92,000	1,000	72.98
	October 2023 - December 2023	92,000	1,000	72.98


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Collar Price Ranges ($/Bbl)(2)
Crude oil collars	July 2022 - September 2022	460,000	5,000	$78.00	-	$107.13
	October 2022 - December 2022	644,000	7,000	80.00	-	104.17
	January 2023 - March 2023	810,000	9,000	75.56	-	91.15
	April 2023 - June 2023	819,000	9,000	75.56	-	91.15
	July 2023 - September 2023	644,000	7,000	76.43	-	92.70
	October 2023 - December 2023	644,000	7,000	76.43	-	92.70

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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 derivative contracts the Company had in place as of September 30, 2021:~~
Period Volume (Bbls) Volume
(Bbls/d)
Wtd. Avg. Crude Price
($/Bbl)(1)
Crude oil swaps
NYMEX WTI October 2021 - December 2021 828,000 9,000 $49.82
January 2022 - March 2022 1,080,000 12,000 65.03
April 2022 - June 2022 1,092,000 12,000 65.28
July 2022 - September 2022 690,000 7,500 63.99
October 2022 - December 2022 598,000 6,500 64.11
ICE Brent October 2021 - December 2021 322,000 3,500 $58.10
Period Volume (Bbls) Volume
(Bbls/d)
Wtd. Avg. Collar Price Ranges
($/Bbl)(2)
Crude oil collars
NYMEX WTI October 2021 - December 2021 92,000 1,000 $42.00 - $50.10
January 2022 - March 2022 225,000 2,500 63.60 - 74.30
April 2022 - June 2022 227,500 2,500 63.20 - 72.41
ICE Brent October 2021 - December 2021 138,000 1,500 $66.67 - $74.80

Period Volume (Bbls) Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(3)
Crude oil basis differential swaps October 2021 - December 2021 644,000 7,000 $0.26
January 2022 - March 2022 360,000 4,000 0.18
April 2022 - June 2022 364,000 4,000 0.18
July 2022 - September 2022 368,000 4,000 0.18
October 2022 - December 2022 368,000 4,000 0.18

Period Volume (Bbls) Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(4)
Crude oil roll differential swaps January 2022 - March 2022 450,000 5,000 $0.60
April 2022 - June 2022 455,000 5,000 0.60
July 2022 - September 2022 460,000 5,000 0.60
October 2022 - December 2022 460,000 5,000 0.60


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Differential ($/Bbl)(3)
Crude oil basis differential swaps	July 2022 - September 2022	552,000	6,000	$0.29
	October 2022 - December 2022	552,000	6,000	0.29


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Differential ($/Bbl)(4)
Crude oil roll differential swaps	July 2022 - September 2022	920,000	10,000	$0.71
	October 2022 - December 2022	920,000	10,000	0.71

(1) These crude oil swap transactions are settled based on ~~either~~ the NYMEX WTI ~~or ICE Brent~~ index price ~~as applicable,~~ on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.

(2) These crude oil collars are settled based on the NYMEX WTI ~~or ICE Brent~~ index price ~~as applicable,~~ on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.

(3) These crude 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 monthly settlement period.

(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.

Period Volume (MMBtu) Volume (MMBtu/d)
Wtd. Avg. Gas Price
($/MMBtu)(1)
Natural gas swaps October 2021 - December 2021 3,680,000 40,000 $2.95
January 2022 - March 2022 2,700,000 30,000 3.00
April 2022 - June 2022 2,730,000 30,000 3.24
July 2022 - September 2022 2,760,000 30,000 3.24
October 2022 - December 2022 1,540,000 16,739 3.15

Period Volume (MMBtu) Volume (MMBtu/d)
Wtd. Avg. Differential
($/MMBtu)(2)
Natural gas basis differential swaps October 2021 - December 2021 4,290,000 46,630 $(0.24)
January 2022 - March 2022 2,700,000 30,000 (0.18)
Period Volume (MMBtu) Volume
(MMBtu/d)
Wtd. Avg. Collar Price Ranges
($/MMBtu)(3)
Natural gas collars October 2021 - December 2021 1,220,000 13,261 $3.15 - $4.65
January 2022 - March 2022 1,800,000 20,000 3.15 - 4.65
April 2022 - June 2022 910,000 10,000 3.00 - 3.68
July 2022 - September 2022 920,000 10,000 3.00 - 3.68
October 2022 - December 2022 310,000 3,370 3.00 - 3.68


	Period	Volume (MMBtu)	Volume (MMBtu/d)	Wtd. Avg. Gas Price ($/MMBtu)(1)
Natural gas swaps	July 2022 - September 2022	2,760,000	30,000	$3.24
	October 2022 - December 2022	1,540,000	16,739	3.15


	Period	Volume (MMBtu)	Volume (MMBtu/d)	Wtd. Avg. Differential ($/MMBtu)(2)
Natural gas basis differential swaps	July 2022 - September 2022	1,840,000	20,000	$(0.45)
	October 2022 - December 2022	1,840,000	20,000	(0.45)
	January 2023 - March 2023	2,250,000	25,000	(1.11)
	April 2023 - June 2023	2,275,000	25,000	(1.11)
	July 2023 - September 2023	2,300,000	25,000	(1.11)
	October 2023 - December 2023	2,300,000	25,000	(1.11)


	Period	Volume (MMBtu)	Volume (MMBtu/d)	Wtd. Avg. Collar Price Ranges ($/MMBtu)(3)
Natural gas collars	July 2022 - September 2022	1,840,000	20,000	$3.50	-	$3.97
	October 2022 - December 2022	2,450,000	26,630	3.87	-	5.06
	January 2023 - March 2023	4,950,000	55,000	4.09	-	7.47
	April 2023 - June 2023	4,095,000	45,000	3.72	-	7.32
	July 2023 - September 2023	4,140,000	45,000	3.72	-	7.32
	October 2023 - December 2023	4,140,000	45,000	3.76	-	7.69
	January 2024 - March 2024	1,820,000	20,000	3.25	-	5.31

(1) These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.

(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 monthly settlement period.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(3) These natural gas collars are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.

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

The following table presents the impact of the Company’s derivative instruments in its consolidated statements of operations for the periods presented:

Three Months Ended September 30, Nine Months Ended September 30,
(in thousands) 2021 2020 2021 2020
Net gain (loss) on derivative instruments $ (44,527) $ (1,968) $ (150,685) $ (40,330)

~~Table of Contents~~

~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~


	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2022		2021		2022		2021


Net gain (loss) on derivative instruments	$	(34,134)	$	(54,959)	$	(163,657)	$	(106,158)

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 tables below summarize 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)	(in thousands)		September 30, 2021						(in thousands)		June 30, 2022
Derivative Assets	Derivative Assets								Derivative Assets
Commodity contracts	Commodity contracts	Prepaid and other current assets	$	3,387	$	(3,387)	$	—	Commodity contracts	Prepaid and other current assets	$	26,356	$	(26,211)	$	145
		Other noncurrent assets	49		(49)		—			Other noncurrent assets	21,874		(17,995)		3,879
Derivative Liabilities	Derivative Liabilities								Derivative Liabilities
Commodity contracts	Commodity contracts	Other current liabilities	79,759		(3,387)		76,372		Commodity contracts	Derivative instruments	109,752		(26,211)		83,541
		Other noncurrent liabilities	3,377		(49)		3,328			Other noncurrent liabilities	20,518		(17,995)		2,523

			December 31, 2020								December 31, 2021
Derivative Assets	Derivative Assets								Derivative Assets
Commodity contracts	Commodity contracts	Prepaid and other current assets	$	6,131	$	(6,131)	$	—	Commodity contracts	Prepaid and other current assets	$	3,284	$	(3,284)	$	—
		Other noncurrent assets	152		$	(100)	52			Other noncurrent assets	585		$	(345)	240
Derivative Liabilities	Derivative Liabilities								Derivative Liabilities
Commodity contracts	Commodity contracts	Other current liabilities	$	24,392	$	(6,131)	$	18,261	Commodity contracts	Derivative instruments	$	38,434	$	(3,284)	$	35,150
		Other noncurrent liabilities	$	100	$	(100)	$	—		Other noncurrent liabilities	345		(345)		—

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

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 primarily lenders under CRP’s ~~credit agreement.~~Credit Agreement. The Company ~~uses~~enters into new hedge arrangements only ~~credit agreement~~with participants ~~to hedge with,~~under its Credit Agreement, 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.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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~~Credit Agreement as referenced above.

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

Note 8—Fair Value Measurements

Recurring Fair Value Measurements

The Company follows 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, 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~~June 30, 2022
Total assets	$	—	$	4,024	$	—
Total liabilities	—		86,064		—
December 31, 2021
Total assets	$	—	$	—240	$	—
Total liabilities	—		~~79,700~~		—
~~December 31, 2020~~
~~Total assets~~	$	—	$	52	$	—
~~Total liabilities~~	—		~~18,261~~35,150		—

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 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 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 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 fair value of these assets may be below their carrying value. 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

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

~~Table of Contents~~

~~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 approach that is based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the expected future net cash flows used for the impairment review and the related fair value measurement of oil and natural gas proved properties include estimates of: (i) oil and gas 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. These inputs require significant judgments and estimates by the Company’s management.

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 the estimated future costs to plug and abandon oil and gas properties and reserve lives. Refer to Note 5—Asset Retirement Obligations for additional information on the Company’s ARO.

Other Financial Instruments

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

The Company’s senior notes and borrowings under its ~~credit agreement~~Credit Agreement are accounted for at ~~cost, and the cost basis of the Company’s Senior Secured Notes issued in the Debt Exchange was measured based on their fair value on the date of the exchange.~~cost. The following table summarizes the carrying values, principal amounts and fair values of these instruments as of the dates indicated:


		September 30, 2021						December 31, 2020							June 30, 2022						December 31, 2021
		Carrying Value		Principal Amount		Fair Value		Carrying Value		Principal Amount		Fair value			Carrying Value		Principal Amount		Fair Value		Carrying Value		Principal Amount		Fair value
Credit facility due 2023(1)		$	205,000	$	205,000	$	205,000	$	330,000	$	330,000	$	330,000
8.00% Senior Secured Notes due 2025(2)		—		—		—		103,901		127,073		114,366
Credit Facility due 2027(1)														Credit Facility due 2027(1)	$	—	$	—	$	—	$	25,000	$	25,000	$	25,000
5.375% Senior Notes due 2026(2)	5.375% Senior Notes due 2026(2)	285,462		289,448		282,212		284,867		289,448		206,955		5.375% Senior Notes due 2026(2)	286,083		289,448		264,129		285,666		289,448		286,554
6.875% Senior Notes due 2027(2)	6.875% Senior Notes due 2027(2)	350,493		356,351		362,373		349,856		356,351		254,791		6.875% Senior Notes due 2027(2)	351,164		356,351		337,643		350,712		356,351		361,696
3.25% Convertible Notes due 2028(2)	3.25% Convertible Notes due 2028(2)	163,982		170,000		223,839		—		—		—		3.25% Convertible Notes due 2028(2)	164,602		170,000		212,577		164,187		170,000		215,279

(1) The carrying values of the amounts outstanding under CRP’s ~~credit agreement~~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 carrying values include associated unamortized debt issuance costs and any debt discounts as reflected in the consolidated balance sheets. The fair values are determined using quoted market prices for these debt securities, a Level 1 classification in the fair value hierarchy, and are based on the aggregate principal amount of the senior notes outstanding.

Note 9—Shareholders' Equity

Stock Repurchase Program

~~Table~~In February 2022, the Company’s Board of ~~Contents~~Directors authorized a stock repurchase program to acquire up to $350 million of the Company’s outstanding Common Stock (the “Repurchase Program”), which is approved to run through April 1, 2024. The Company intends to use the Repurchase Program to reduce its shares of Common Stock outstanding and plans to fund these repurchases with cash on hand and cash flows from operations. Repurchases may be made from time to time in the open-market or via privately negotiated transactions at the Company’s discretion and will be subject to market conditions, applicable legal requirements, available liquidity, compliance with the Company’s debt and other agreements and other factors. The Repurchase Program does not require any specific number of shares to be acquired and can be modified or discontinued by the Company’s Board of Directors at any time. There were no shares purchased under the Repurchase Program during the six months ended June 30, 2022. Due to restrictions related to the Merger, the Company has been unable to make or initiate any share repurchases under the Repurchase Program since the announcement and therefore, will not be able to begin repurchasing its shares until the pending Merger closes or is otherwise terminated.

~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

Note 9—10—Earnings Per Share

Basic earnings per share (“EPS”) is calculated by dividing net income ~~available to Class A Common Stock~~ by the weighted average shares of 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 Common Stock outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted EPS calculation consists of (i) unvested equity-based restricted stock and performance stock units, outstanding stock options, withholding amounts from the employee stock purchase plan and warrants (prior to their expiration in 2021), all using the

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

treasury stock method, and (ii) ~~the Company’s Class C common stock outstanding, prior to the conversion of remaining Class C shares in the second quarter of 2020, and~~ potential shares issuable under our Convertible Senior Notes, ~~both~~ using the “if-converted” method, which is net of tax.

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~~each period:

Three Months Ended September 30, Nine Months Ended September 30,
(in thousands, except per share data) 2021 2020 2021 2020
Net income (loss) attributable to Class A Common Stock $ 37,124 $ (51,529) $ (22,576) $ (594,182)
Add: Income from Convertible Senior Notes 1,584 — — —
Adjusted net income (loss) attributable to Class A Common Stock $ 38,708 $ (51,529) $ (22,576) $ (594,182)
Basic weighted average shares of Class A Common Stock outstanding 281,162 278,017 279,781 277,038
Add: Dilutive effects of potential common stock 7,973 — — —
Add: Dilutive effects of Convertible Senior Notes 27,074 — — —
Diluted weighted average shares of Class A Common Stock outstanding 316,209 278,017 279,781 277,038
Basic net earnings (loss) per share of Class A Common Stock $ 0.13 $ (0.19) $ (0.08) $ (2.14)
Diluted net earnings (loss) per share of Class A Common Stock $ 0.12 $ (0.19) $ (0.08) $ (2.14)


	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands, except per share data)	2022		2021		2022		2021
Net income (loss)	$	191,826	$	(25,055)	$	207,628	$	(59,700)
Add: Interest on Convertible Senior Notes, net of tax	1,306		—		2,611		—
Adjusted net income (loss)	$	193,132	$	(25,055)	$	210,239	$	(59,700)

Basic weighted average shares of Common Stock outstanding	284,992		279,185		284,922		279,061
Add: Dilutive effects of equity awards and ESPP shares	8,038		—		7,897		—
Add: Dilutive effects of Convertible Senior Notes	27,074		—		27,074		—
Diluted weighted average shares of Common Stock outstanding	320,104		279,185		319,893		279,061

Basic net earnings (loss) per share of Common Stock	$	0.67	$	(0.09)	$	0.73	$	(0.21)
Diluted net earnings (loss) per share of Common Stock	$	0.60	$	(0.09)	$	0.66	$	(0.21)

The Company recognized a net loss during the nine months ended September 30, 2021 and during the three and nine months ended September 30, 2020. As a result, all potential common shares were anti-dilutive for each of those three periods and have been excluded from the calculation of diluted net earnings per share accordingly for such periods. The following table presents shares excluded from the diluted earnings per share calculation for the periods presented as their impact was anti-dilutive:


		Three Months Ended September 30,		Nine Months Ended September 30,			Three Months Ended June 30,		Six Months Ended June 30,
(in thousands)	(in thousands)	2021	2020	2021	2020	(in thousands)	2022	2021(1)	2022	2021(1)
Out-of-the-money stock options	Out-of-the-money stock options	2,215	2,469	2,250	3,983	Out-of-the-money stock options	2,049	2,241	2,073	2,267
Restricted stock	Restricted stock	83	9,572	8,780	6,607	Restricted stock	—	8,769	—	9,167
Performance stock units						Performance stock units	—	—	224	199
Employee Stock Purchase Plan	Employee Stock Purchase Plan	28	—	46	93	Employee Stock Purchase Plan	—	68	—	54
Weighted average shares of Class C Common Stock		—	—	—	348
Convertible Senior Notes						Convertible Senior Notes	—	27,074	—	27,074
Warrants	Warrants	8,000	8,000	8,000	8,000	Warrants	—	8,000	—	8,000
Performance stock units		—	—	133	—
Convertible Senior Notes		—	—	27,074	—

(1) The Company recognized a net loss during the three and six months ended June 30, 2021, and therefore all potentially dilutive securities were anti-dilutive and excluded from the calculation of diluted net earnings per share.

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

Note ~~10—~~11—Transactions with Related Parties

Riverstone Investment Group LLC and its affiliates (“Riverstone”) beneficially own a 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 included in the consolidated statements of operations for the periods indicated, as well as the related net receivables outstanding as of the balance sheet dates:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	(in thousands)	2021		2020		2021		2020		(in thousands)	2022		2021		2022		2021
Oil and gas sales	Oil and gas sales	$	2,715	$	1,610	$	6,846	$	3,272	Oil and gas sales	$	9,107	$	3,056	$	18,590	$	4,132
Gathering, processing and transportation expenses	Gathering, processing and transportation expenses	1,715		1,464		4,556		3,526		Gathering, processing and transportation expenses	2,150		1,636		4,669		2,841


(in thousands)	(in thousands)	September 30, 2021		December 31, 2020		(in thousands)	June 30, 2022		December 31, 2021
Accounts receivable, net(1)	Accounts receivable, net(1)	$	4,229	$	994	Accounts receivable, net(1)	$	3,889	$	5,562

(1) Represents amounts due from Lucid and are presented net of unpaid processing fees as of the indicated period end date.

~~Senior Secured Notes~~

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CENTENNIAL RESOURCE DEVELOPMENT, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Riverstone held $106.3 million of the Company’s Senior Secured Notes as of December 31, 2020. In April 2021, the Company redeemed all of its Senior Secured Notes, including the portion held by Riverstone. In connection with this redemption, the Company paid ~~$3.8 million~~ in accrued interest associated with the Senior Secured Notes, including $3.1 million to Riverstone during the nine months ended September 30, 2021. No interest payments were made to Riverstone during the three or nine months ended September 30, 2020.

Note ~~11—~~12—Commitments and Contingencies

Commitments

The Company routinely enters into, extends or amends operating agreements in the ordinary course of business. During the six months ended June 30, 2022, the Company entered into a two-year purchase agreement to buy frac’ sand used in its well fracture stimulation process. Under the terms of this take-or-pay agreement, the Company is obligated to purchase a minimum volume of frac’ sand at a fixed price. The obligation is $39.1 million, which represents the minimum financial commitment pursuant to the terms of the contract from June 30, 2022 through March 31, 2024. There ~~have~~has been no other material, non-routine changes in commitments during the ~~nine~~six months ended ~~September~~June 30, ~~2021.~~2022. Please refer to Note 13—Commitments and Contingencies included in Part II, Item 8 in the Company’s ~~2020~~2021 Annual Report.

The Company has a firm crude oil sales agreement with a large integrated oil company, and in the first quarter of 2021, new pricing terms under this agreement went into effect. Utilizing this integrated oil company’s transport capacity out of the Permian Basin, the agreement provides for firm gross sales of 30,000 Bbls/d over the next 4 years and is based upon prevailing market prices of ICE Brent less contractual differentials. These pricing terms are resulting in realized prices that currently have wider differentials than those being realized under the Company’s other oil marketing agreements. However, if the oil price differential between the ICE Brent and NYMEX WTI indices widen in the future, the oil price realized under this delivery commitment will improve relative to the prices realized under the Company’s other oil sales contracts. Under-delivery of volumes that are committed under this agreement would result in a financial obligation to the Company, although the Company’s current production level (on a gross basis) is, and the Company believes its future production will be, sufficient to fulfill this physical delivery commitment.

Contingencies

The Company may at times be subject to various commercial or regulatory claims, prior period adjustments from service providers, 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, other than those discussed below, that are reasonably possible to occur will have a material adverse effect on the Company’s financial position, results of operations, or cash flows.

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

In February 2021, the Permian Basin was impacted by record-low temperatures and a severe winter storm (“Winter Storm Uri”) that resulted in multi-day electrical outages and shortages, pipeline and infrastructure freezes, transportation disruptions, and regulatory actions in Texas, which led to significant increases in gas prices, gathering, processing and transportation fees and electrical rates during this time. As a result, many oil and gas operations, including upstream producers like the Company, as well as gas processors and purchasers, and transportation providers experienced operational disruptions. During this time, the Company was unable to utilize the entire volume of its reserved capacity on pipelines and as a result has made certain force majeure declarations. One third-party transportation provider has filed a lawsuit against the Company claiming compensation for the full amount of the reserved capacity, both utilized and unutilized. The Company has made a payment for the utilized capacity and filed a separate lawsuit against the transportation provider requesting declaratory relief for the purpose of construing the provisions of the transportation agreement relating to the unutilized capacity. At this time, the Company believes that a loss is reasonably possible in relation to these matters and such amount could range from zero to $7.6 million, and no amount in that range is a better estimate than any other.

Other than the matter above, 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—~~13—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 prices of oil, natural gas, and NGLs fluctuate to remain competitive with other available oil, natural gas, and NGLs supplies both globally (in the case of crude oil) and locally.

Oil and gas revenues presented within the consolidated statements of operations relate to the sale of oil, natural gas and NGLs as shown below:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Operating revenues (in thousands):	Operating revenues (in thousands):									Operating revenues (in thousands):
Oil sales	Oil sales	$	201,447	$	119,966	$	512,278	$	363,571	Oil sales	$	349,591	$	177,105	$	612,358	$	310,831
Natural gas sales	Natural gas sales	43,800		11,907		106,266		29,052		Natural gas sales	68,030		27,015		107,048		62,466
NGL sales	NGL sales	43,258		17,228		94,929		39,756		NGL sales	55,033		28,457		100,525		51,671
Oil and gas sales	Oil and gas sales	$	288,505	$	149,101	$	713,473	$	432,379	Oil and gas sales	$	472,654	$	232,577	$	819,931	$	424,968

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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 gathering and processing entity at the inlet of the gas gathering 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.

~~Table of Contents~~

~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

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 such time, the volumes delivered and sales prices can be reasonably estimated and amounts due from customers are accrued in Accounts receivable, net in the consolidated balance sheets. As of ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, such receivable balances were ~~$82.1~~$114.2 million and ~~$41.7~~$57.3 million, respectively.

The Company records any differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Historically, any identified differences between revenue estimates and actual revenue received have not been significant. For the three and ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 and ~~2020,~~2021, 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~~14—Subsequent Events

~~At contract inception,~~Credit Facility

On July 15, 2022, CRP and the Company ~~determines whether or not an arrangement contains~~entered into the first amendment to its Credit Agreement (the “Amendment”). The Amendment, among other things, waives compliance with certain restrictive covenants and provides the lenders’ consent to a ~~lease. However,~~planned Pre-Merger Reorganization (as defined within the Amendment) in ~~connection with~~order to enable the ~~implementation of ASC Topic 842,~~ ~~Leases~~ ~~(“ASC 842”), this assessment was made~~Merger. In addition, the Amendment increases the elected commitments under the Credit Agreement to $1.5 billion from $750 million and the borrowing base to $2.5 billion from $1.15 billion. The Amendment is subject to and effective as of the ~~adoption~~closing date of ~~ASC 842. Upon determination of a lease, a lease right-of-use (“ROU”) asset~~the Merger and ~~related liability are recorded based on~~will be terminated if the ~~present value of the future lease payments over the lease term. ROU assets represent the Company’s right~~Merger has not occurred prior to ~~use an underlying asset for the lease term, and lease liabilities represent the obligation to make future lease payments arising from the lease.~~

~~The Company has operating leases for drilling rig contracts, office rental agreements, and other wellhead equipment. As of September~~November 30, 2021, these leases have remaining lease terms ranging from one month to 10 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.

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 and the specific lease term. The table below summarizes the Company’s weighted-average discount rate and weighted-average remaining lease term as of the period presented.


	~~As of September 30, 2021~~
~~Weighted-average discount rate~~	~~4.47~~	%
~~Weighted-average remaining lease term (months)~~	~~107~~

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.

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

Variable lease payments are recognized in the period in which they are 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 as either expenses to the consolidated statements of operations or capitalized to the consolidated balance sheets. The following table presents the components of the Company’s lease expenses for the periods presented.
Three Months Ended September 30, Nine Months Ended September 30,
(in thousands) 2021 2020 2021 2020
Lease costs
Operating lease cost $ 906 $ 1,227 $ 2,621 $ 7,059
Variable lease cost 55 53 77 4,538
Short-term lease cost 9,209 5,512 26,376 34,529
Total lease cost $ 10,170 $ 6,792 $ 29,074 $ 46,126

~~The following table presents supplemental cash flow information related to the Company’s leases for the periods presented.~~

Nine Months Ended September 30,
(in thousands) 2021 2020
Operating lease liability payments:
Net cash used in operating activities $ 2,311 $ 5,257
Net cash used in investing activities $ — $ 1,802
Right-of-use assets recognized (derecognized) with offsetting operating lease liabilities $ 15,450 $ (3,711)
2022.

~~Maturities of the Company’s long-term operating lease liabilities by fiscal year as of September 30, 2021 are as follows:~~

(in thousands)
Total(2)
2021(1)
$ 468
2022 1,898
2023 2,985
2024 2,670
2025 2,086
2026 and thereafter 12,669
Total lease payments 22,776
Less: imputed interest (4,565)
Present value of lease liabilities (3)
$ 18,211

~~(1)~~ ~~Excludes payments made during the nine months ended September 30, 2021.~~

~~(2)~~ ~~Total lease payments exclude variable lease payments which can be charged under the terms of the lease agreements.~~

~~(3)~~ ~~This amount is included in current and noncurrent liabilities in the line item~~ ~~Operating lease liabilities~~ ~~in the consolidated balance sheets as of September 30, 2021.~~

3128

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~Note 14—Subsequent Events~~

~~Asset Divestiture~~

On October 27, 2021, the Company entered into a purchase and sale agreement for the sale of approximately 6,200 net leasehold acres at closing for an unadjusted purchase price of $101 million. The divested assets represent non-core acreage that is primarily undeveloped but which also contains 20 producing wells located on the southernmost portion of the Company’s position in Reeves County, Texas. The producing properties included in this divestiture averaged 1,600 Boe/d (64% oil) during the third quarter of 2021. The Company expects to recognize a net gain of approximately $36.5 million as a result of this divestiture. The transaction is expected to close in December of 2021, subject to customary closing terms and conditions, and the Company plans to use the net proceeds from the sale to repay a portion of its borrowings outstanding under its Credit Agreement.

~~Expiring Warrants~~

Simultaneously with the closing of the Company’s initial public offering on February 29, 2016, 8,000,000 warrants were purchased by Silver Run Sponsor, LLC, a Riverstone affiliate, in a private placement (the “Private Placement Warrants”), and each Private Placement Warrant was exercisable for one share of Class A Common Stock at a price of $11.50 per share. These warrants were still outstanding as of September 30, 2021. However, on October 11, 2021, all of the 8,000,000 Private Placement Warrants expired unexercised.

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~~CENTENNIAL RESOURCE DEVELOPMENT, INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

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

The following discussion and analysis of our financial condition and results of operations 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, future market prices for oil, natural gas and NGLs, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, the success of our pending merger transaction, continued and future impacts of ~~Coronavirus Disease 2019 (“COVID-19”)~~COVID-19 and other uncertainties, as well as those factors discussed ~~above~~ in “Cautionary Statement ~~Regarding~~Concerning Forward-Looking Statements” and under the heading “Item 1A. Risk Factors” in this Quarterly Report and our ~~2020~~2021 Annual Report 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 oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. Our ~~capital programs are focused on projects that we believe provide the highest~~principal business objective is to increase shareholder value by efficiently developing our oil and natural gas assets in an environmentally and socially responsible way, with an overall objective of improving our rates of return ~~on capital.~~and generating sustainable free cash flow. 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 ~~2020~~demand for oil and natural gas has been significantly impacted by the worldwide outbreak of COVID-19, specifically regarding the uncertainty ~~regarding its~~surrounding the virus’s impact and because of various governmental actions taken to mitigate the ~~effects~~spread of ~~COVID-19 resulted in an unprecedented decline in~~ the ~~demand for~~virus. Concurrently, global oil and natural gas ~~throughout 2020. In addition, the decision~~supplies have been disrupted by ~~Saudi Arabia to drastically reduce export prices and increase oil~~ production ~~in March 2020 (the “Saudi-Russia oil price war”) followed by~~ curtailment agreements among the Organization of Petroleum Exporting Countries ~~(“OPEC”) and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. However, in April of 2020, the members of OPEC~~ and other oil producing countries (“OPEC+”) ~~agreed to reduce their crude oil production throughout the year, while U.S. producers substantially~~and reduced ~~or suspended~~ drilling and completion activity ~~due to low oil prices~~from U.S. producers. Both OPEC+ output and ~~poor economics.~~

The demand for oil and natural gas continued to remain low in early 2021 due to continued uncertainty regarding the impacts of COVID-19. OPEC+ extended their production cuts through the first quarter of 2021 and began to gradually increase output during the second quarter of 2021 with more substantial output increases beginning in August 2021 through September 2022. U.S. drilling activity ~~began to increase in the fourth quarter of~~has increased since 2020 ~~and has continued to increase steadily since. These~~levels; however, these factors have only led to a gradual increase in oil and gas supply, ~~but~~and global supply has not returned ~~global supply~~ to pre-pandemic levels. ~~Meanwhile,~~Further in the first half of 2022, Russia’s invasion of Ukraine and global sanctions placed on Russia in response have created additional downward pressures on the supply of oil and natural gas. Meanwhile, demand for oil and gas has risen steadily throughout 2021 and 2022 due to the availability of COVID-19 vaccinations, ~~less governmental~~fewer government mandated restrictions and the ~~global~~global-wide transition away from coal to natural gas. Despite governmental actions from several countries to release a portion of their strategic petroleum reserves, global oil inventories have continued to decline due to the resulting supply and demand imbalances. These factors, among others, have aided in the recovery of global commodity prices ~~during~~throughout 2021 and have led to heightened commodity prices in the first ~~nine months~~half of ~~2021.~~2022. Specifically, WTI spot prices for crude oil reached a high of ~~$75.45~~$123.70 per barrel on ~~September 27, 2021~~March 8, 2022, from a low of negative $37.63 per barrel on April 20, ~~2020 (which was due to depressed demand and insufficient storage capacity, particularly at the WTI physical settlement location in Cushing, Oklahoma).~~2020. Similarly, the ~~average~~ Henry Hub index price for natural gas reached ~~$4.28 during the third quarter~~a high of ~~2021, which was more than double~~$9.46 per MMBtu on June 9, 2022, from a low of ~~the average Henry Hub price of $1.95 for the comparable 2020 period.~~$1.33 per MMBtu on September 22, 2020.

The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, the continued effects from COVID-19 and variant strains of the virus, geopolitical events, federal and state government regulations, weather conditions, the global transition to alternative energy sources, supply chain constraints and other factors. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of ~~2019:~~2020:


		2019								2020								2021							2020								2021								2022
		Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3			Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2
Crude oil (per Bbl)	Crude oil (per Bbl)	$	54.90	$	59.81	$	56.45	$	56.94	$	46.19	$	28.00	$	40.93	$	42.66	$	57.84	$	66.06	$	70.56	Crude oil (per Bbl)	$	46.19	$	28.00	$	40.93	$	42.66	$	57.84	$	66.06	$	70.56	$	77.09	$	94.40	$	108.34
Natural gas (per MMBtu)	Natural gas (per MMBtu)	$	2.88	$	2.51	$	2.33	$	2.34	$	1.88	$	1.65	$	1.95	$	2.47	$	3.44	$	2.88	$	4.28	Natural gas (per MMBtu)	$	1.88	$	1.65	$	1.95	$	2.47	$	3.44	$	2.88	$	4.28	$	4.74	$	4.60	$	7.39

Lower commodity prices ~~(including realized differentials)~~ and lower futures curves for oil and gas prices can result in ~~further~~ impairments of our proved oil and natural gas properties or undeveloped acreage ~~(such as the impairments incurred in the first~~

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~~quarter of 2020)~~ and may materially and adversely affect our ~~future business,~~operating cash flows, liquidity, financial condition, results of operations, ~~operating cash flows, liquidity~~future business, and/or our ability to finance planned capital expenditures. Lower realized prices may also reduce the borrowing base under CRP’s credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to

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immediately repay a portion of the debt outstanding under the credit agreement. Additionally, ~~the~~ lower ~~price environment and its impact to~~prices can affect our operations, which could impact our ability to comply with the covenants under our credit agreement and senior notes.

Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. In addition, the U.S. inflation rate has been steadily increasing during 2021 and 2022. These inflationary pressures may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise.

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, vendors, suppliers and the communities in which we operate. Our operational employees have been and are currently able to work on site, while certain non-operational employees have been working remotely part-time and then also reporting to our offices on a ~~limited~~part-time basis. We have taken various precautionary measures with respect to our operational employees, direct contractors and employees who returned to our offices or job sites ~~such as (i) requesting that they~~and 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 or office, (ii) self-quarantining any employees or contractors who have shown signs or symptoms of COVID-19 (regardless of whether such person has been confirmed to be infected), (iii) imposing certain mask and social distancing requirements on work sites and at our officesfollowed ~~, and (iv) encouraging all employees and contractors to follow~~ the Center of Disease Control (the “CDC”) recommended preventive measures ~~(including those mentioned above)~~ to limit the spread of COVID-19. We have continued to update our safety protocols in alignment with CDC guidance and ~~governmental mandates, and have been able to reduce some requirements if employees, customers, vendors, or suppliers are fully vaccinated.~~government mandates. We have not experienced any significant operational disruptions, ~~(including~~including disruptions from our suppliers or service ~~providers)~~providers, as a result of the COVID-19 outbreak.

~~2021~~2022 Highlights and Future Considerations

Pending Merger

On May 19, 2022, we entered into a Business Combination Agreement (the “Business Combination Agreement”) with Colgate Energy Partners III, LLC (“Colgate”), which provides for the combination of Centennial and Colgate in a merger of equals transaction (the “Merger”). Colgate is an independent oil and gas company focused on the acquisition, development, exploration and production of oil and natural gas properties in the Permian Basin. Colgate owns approximately 105,000 net leasehold acres and 25,000 net royalty acres in Reeves and Ward counties in Texas and Eddy County in New Mexico. We believe that the Merger will provide significant increases to operational and financial scale, drive accretion across our key financial and operating metrics, and enhance the combined company’s shareholder returns.

Pursuant to the Business Combination Agreement, all membership interests in CRP issued and outstanding will be converted into units in the surviving company (“Surviving Company Units”) equal to the number of shares of our Class A common stock (“Common Stock”) that are outstanding at such time, and all of the membership interest in Colgate will be exchanged for 269,300,000 shares of Class C common stock (with underlying Surviving Company Units) and $525 million in cash. The shares of Class C common stock will represent a noncontrolling interest in the Surviving Company.

The transaction has been unanimously approved by the Boards of Directors of both companies. The definitive proxy statement has been filed with the SEC and the shareholder meeting is scheduled for August 29, 2022, where the Merger will be voted on by our shareholders. The Merger is expected to close shortly after the shareholder meeting subject to customary closing conditions, including, among others, receipt of the required approvals from our shareholders.

Operational Highlights

We operated a two-rig drilling program during the first ~~nine~~six months of ~~2021,~~2022, which enabled us to complete and bring online 3331 gross operated wells with an average effective lateral length of approximately ~~9,000~~9,100 feet.

In February 2021, the Permian Basin was impacted by record-low temperatures and a severe winter storm (“Winter Storm Uri”) that caused multi-day electrical outages and shortages, pipeline and infrastructure freezes, and transportation disruptions, which further led to significant increases in gas prices, gathering, processing and transportation fees and electrical rates during this time. Our operations were impacted by Winter Storm Uri and led to a partial shut-in of certain wells and associated production for about seven days during the event. Refer to the discussion below for the current impacts from Winter Storm Uri on our results of operations during the nine months ended September 30, 2021.

Financing Highlights

On ~~March 19, 2021,~~February 18, 2022, we ~~issued $150.0~~closed on a new five-year revolving credit facility (the “Credit Agreement”), which replaced our previous credit agreement that was set to mature on May 4, 2023. The elected commitments under the new Credit Agreement increased to $750 million from $700 million under our previous facility, and the borrowing base increased to $1.15 billion from $700 million previously. The new Credit Agreement will mature in February 2027.

In February 2022, our Board of Directors authorized a stock repurchase program to acquire up to $350 million of ~~3.25% senior convertible notes due 2028~~our outstanding Common Stock, which program is approved to run through April 1, 2024 (the ~~“Convertible Senior Notes”~~“Repurchase Program”) ~~in a public offering. On March 26, 2021,~~. We intend to use the ~~Company issued an additional $20.0 million~~Repurchase Program to reduce shares of ~~Convertible Senior Notes pursuant~~our Common Stock outstanding and plan to fund these share repurchases with cash on hand and cash flows from operations. Due to restrictions related to the ~~exercise~~Merger, we have been unable to make or initiate any share repurchases under the Repurchase Program since the announcement and therefore, we will not be able to begin repurchasing our shares until the pending Merger closes or is otherwise terminated.

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On July 15, 2022, we entered into the first amendment to our Credit Agreement (the “Amendment”). The Amendment, among other things, waives compliance with certain restrictive covenants and provides the lenders’ consent to a planned Pre-Merger Reorganization (as defined within the Amendment) in order to enable the Merger. In addition, the Amendment increases the elected commitments under our Credit Agreement to $1.5 billion from $750 million and the borrowing base to $2.5 billion from $1.15 billion. The Amendment is subject to and effective as of the ~~underwriters’ over-allotment option~~closing date of the Merger and will be terminated if the Merger has not occurred prior to purchase additional notes. The issuance resulted in net proceeds of $163.6 million, after deducting debt issuance costs of $6.4 million, and such proceeds were used to fund the cost of entering into capped call spread transactions totaling $14.7 million and to repay borrowing outstanding under CRP’s revolving credit facility. In April 2021, we redeemed at par all of our 2025 senior secured notes ($127.1 million), which was the intended use of proceeds from the Convertible Senior Notes offering.

~~In connection with CRP’s credit facility fall 2021 semi-annual borrowing base redetermination, the facility’s borrowing base and amount of elected commitments were reaffirmed at $700.0 million.~~November 30, 2022.

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Results of Operations

Three Months Ended ~~September~~June 30, ~~2021~~2022 Compared to Three Months Ended ~~September~~June 30, ~~2020~~2021

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:


		Three Months Ended September 30,				Increase/(Decrease)					Three Months Ended June 30,				Increase/(Decrease)
		2021		2020		$		%			2022		2021		$		%
Net revenues (in thousands):	Net revenues (in thousands):									Net revenues (in thousands):
Oil sales	Oil sales	$	201,447	$	119,966	$	81,481	68	%	Oil sales	$	349,591	$	177,105	$	172,486	97	%
Natural gas sales	Natural gas sales	43,800		11,907		31,893		268	%	Natural gas sales	68,030		27,015		41,015		152	%
NGL sales	NGL sales	43,258		17,228		26,030		151	%	NGL sales	55,033		28,457		26,576		93	%
Oil and gas sales	Oil and gas sales	$	288,505	$	149,101	$	139,404	93	%	Oil and gas sales	$	472,654	$	232,577	$	240,077	103	%

Average sales prices:	Average sales prices:									Average sales prices:
Oil (per Bbl)	Oil (per Bbl)	$	65.31	$	36.95	$	28.36	77	%	Oil (per Bbl)	$	104.69	$	60.99	$	43.70	72	%
Effect of derivative settlements on average price (per Bbl)	Effect of derivative settlements on average price (per Bbl)	(8.37)		(9.82)		1.45		15	%	Effect of derivative settlements on average price (per Bbl)	(16.97)		(12.59)		(4.38)		(35)	%
Oil net of hedging (per Bbl)	Oil net of hedging (per Bbl)	$	56.94	$	27.13	$	29.81	110	%	Oil net of hedging (per Bbl)	$	87.72	$	48.40	$	39.32	81	%

Average NYMEX price for oil (per Bbl)	Average NYMEX price for oil (per Bbl)	$	70.56	$	40.93	$	29.63	72	%	Average NYMEX price for oil (per Bbl)	$	108.34	$	66.06	$	42.28	64	%
Oil differential from NYMEX	Oil differential from NYMEX	(5.25)		(3.98)		(1.27)		(32)	%	Oil differential from NYMEX	(3.65)		(5.07)		1.42		28	%

Natural gas (per Mcf)	Natural gas (per Mcf)	$	3.99	$	1.15	$	2.84	247	%	Natural gas (per Mcf)	$	6.22	$	2.55	$	3.67	144	%
Effect of derivative settlements on average price (per Mcf)	Effect of derivative settlements on average price (per Mcf)	(0.27)		(0.25)		(0.02)		(8)	%	Effect of derivative settlements on average price (per Mcf)	(1.55)		(0.09)		(1.46)		(1,622)	%
Natural gas net of hedging (per Mcf)	Natural gas net of hedging (per Mcf)	$	3.72	$	0.90	$	2.82	313	%	Natural gas net of hedging (per Mcf)	$	4.67	$	2.46	$	2.21	90	%

Average NYMEX price for natural gas (per Mcf)	Average NYMEX price for natural gas (per Mcf)	$	4.28	$	1.95	$	2.33	119	%	Average NYMEX price for natural gas (per Mcf)	$	7.39	$	2.88	$	4.51	157	%
Natural gas differential from NYMEX	Natural gas differential from NYMEX	(0.29)		(0.80)		0.51		64	%	Natural gas differential from NYMEX	(1.17)		(0.33)		(0.84)		(255)	%

NGL (per Bbl)	NGL (per Bbl)	$	40.16	$	12.58	$	27.58	219	%	NGL (per Bbl)	$	44.77	$	30.37	$	14.40	47	%

Net production:	Net production:									Net production:
Oil (MBbls)	Oil (MBbls)	3,085		3,247		(162)		(5)	%	Oil (MBbls)	3,339		2,904		435		15	%
Natural gas (MMcf)	Natural gas (MMcf)	10,977		10,354		623		6	%	Natural gas (MMcf)	10,941		10,613		328		3	%
NGL (MBbls)	NGL (MBbls)	1,077		1,370		(293)		(21)	%	NGL (MBbls)	1,230		937		293		31	%
Total (MBoe)(1)	Total (MBoe)(1)	5,991		6,342		(351)		(6)	%	Total (MBoe)(1)	6,392		5,610		782		14	%

Average daily net production:	Average daily net production:									Average daily net production:
Oil (Bbls/d)	Oil (Bbls/d)	33,529		35,292		(1,763)		(5)	%	Oil (Bbls/d)	36,696		31,912		4,784		15	%
Natural gas (Mcf/d)	Natural gas (Mcf/d)	119,311		112,545		6,766		6	%	Natural gas (Mcf/d)	120,225		116,629		3,596		3	%
NGL (Bbls/d)	NGL (Bbls/d)	11,707		14,885		(3,178)		(21)	%	NGL (Bbls/d)	13,507		10,297		3,210		31	%
Total (Boe/d)(1)	Total (Boe/d)(1)	65,121		68,934		(3,813)		(6)	%	Total (Boe/d)(1)	70,240		61,647		8,593		14	%

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

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Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the three months ended ~~September~~June 30, ~~2021~~2022 were ~~$139.4~~$240.1 million (or ~~93%~~103%) higher than total net revenues for the three months ended ~~September~~June 30, ~~2020.~~2021. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

Average realized sales prices for oil, residue gas and NGLs increased in the ~~third~~second quarter of ~~2021~~2022 compared to the same ~~2020~~2021 period by ~~77%~~72%, ~~247%~~144% and ~~219%~~47%, respectively. The ~~77%~~72% increase in the average realized oil price ~~before the effects of hedging~~ was mainly the result of higher ~~(72%~~(64%) NYMEX crude prices between periods, ~~which was partially offset by wider~~as well as improved oil differentials ($~~1.27~~1.42 per Bbl ~~wider) oil differentials.~~narrower). The ~~247% increase in the~~ average realized sales price of natural gas ~~before the effects of hedging was~~increased 144% due to higher ~~(119%~~(157%) NYMEX gas prices between periods, ~~and improved (by $0.51~~partially offset by wider gas differentials ($0.84 per ~~Mcf) gas differentials.~~Mcf wider). The 47% increase in average realized NGL prices ~~of 219%~~ between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in the ~~third~~second quarter of ~~2021~~2022 as compared to the ~~third~~second quarter of ~~2020.~~2021. The market prices for oil, natural gas and NGLs have all been impacted by ~~higher~~ global ~~demand~~supply constraints for oil and gas ~~compared to the third quarter of 2020 when prices remained depressed~~throughout 2021 and 2022, as ~~a result of~~well as increasing demand worldwide as global economies emerge from COVID-19 era lockdowns and ~~supply disruptions from the Saudi-Russia oil price war~~restrictions, as discussed in the market conditions section above.

Net production volumes for oil, natural gas and NGLs ~~decreased 5%~~increased 15%, 3% and ~~21%~~31%, respectively, ~~while natural gas increased 6%~~between periods. The increase in oil production resulted from our successful drilling program in the ~~third~~Delaware Basin. Since the second quarter of 2021, compared to the same 2020 period. The crude oil production volume decrease was primarily the result of normal production decline across our existing wells. Oil volume declines in the third quarter of 2021 were additionally impacted by less drilling and completion activity over the past 12 months as a result of depressed oil and gas prices, which resulted in only 33we placed 50 wells ~~being placed~~ on production, ~~since the third quarter of 2020. This~~which added ~~1,103~~1,649 MBbls of net oil production to the three months ended ~~September~~June 30, ~~2021~~2022, as compared to 5828 wells brought online since the ~~third~~second quarter of ~~2019~~2020 that added ~~1,363~~872 MBbls of net oil production to the ~~third~~second quarter of ~~2020.~~2021. These oil volume increases were partially offset by normal production decline across our existing wells. Natural gas and NGLs are produced concurrently with our crude oil volumes, which typically ~~resulting~~results in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. However, ~~during the third quarter of 2021,~~ the main processor of our raw gas operated in ~~full ethane-rejection,~~partial ethane-recovery during the second quarter of 2022, as compared to operating in full ~~ethane-recovery~~ethane-rejection during the ~~entire 2020 period. Additionally,~~ ~~the amount of gas flared as a percentage of wellhead gas produced was lessduring the third quarter of~~ 2021 ~~as compared to the same 2020 period.~~ ~~Both of these factors combined~~period, and this resulted in ~~an increase in the amount of~~fewer natural gas ~~recovered~~volumes and ~~sold~~more NGLs being recovered from our wet gas stream ~~between periods, while the variations in ethane-rejection resulted in fewer NGLs being recovered~~ during the ~~2021~~2022 period.

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


		Three Months Ended September 30,						Increase/(Decrease)						Three Months Ended June 30,						Increase/(Decrease)
		2021			2020			Change			%			2022			2021			Change			%
Operating costs (in thousands):	Operating costs (in thousands):												Operating costs (in thousands):
Lease operating expenses	Lease operating expenses	$	28,685		$	24,543		$	4,142		17	%	Lease operating expenses	$	28,900		$	22,976		$	5,924		26	%
Severance and ad valorem taxes	Severance and ad valorem taxes	17,800			7,839			9,961			127	%	Severance and ad valorem taxes	34,695			15,784			18,911			120	%
Gathering, processing and transportation expenses	Gathering, processing and transportation expenses	24,164			19,130			5,034			26	%	Gathering, processing and transportation expenses	25,756			19,494			6,262			32	%
Operating cost metrics:	Operating cost metrics:												Operating cost metrics:
Lease operating expenses (per Boe)	Lease operating expenses (per Boe)	$	4.79		$	3.87		$	0.92		24	%	Lease operating expenses (per Boe)	$	4.52		$	4.10		$	0.42		10	%
Severance and ad valorem taxes (% of revenue)	Severance and ad valorem taxes (% of revenue)	6.2		%	5.3		%	0.9		%	17	%	Severance and ad valorem taxes (% of revenue)	7.3		%	6.8		%	0.5		%	7	%
Gathering, processing and transportation expenses (per Boe)	Gathering, processing and transportation expenses (per Boe)	$	4.03		$	3.02		$	1.01		33	%	Gathering, processing and transportation expenses (per Boe)	$	4.03		$	3.47		$	0.56		16	%

Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended ~~September~~June 30, ~~2021~~2022 increased ~~$4.1~~$5.9 million compared to the three months ended ~~September~~June 30, ~~2020.~~2021. Higher LOE for the ~~third~~second quarter of ~~2021~~2022 was primarily related to (i) ~~higher chemical~~a $2.9 million increase in electricity costs ~~for treating natural gas;~~between periods due to electricity credits received during the second quarter of 2021 related to the severe winter storm in the Permian Basin (“Winter Storm Uri”) that were not similarly received in 2022; (ii) ~~increased environmental expenses and preventative maintenance costs;~~an increase in workover expense of $0.9 million between periods; and (iii) higher fixed and variable costs associated with our higher well count, which increased to ~~413~~435 gross operated horizontal wells as of ~~September~~June 30, ~~2021~~2022 from ~~387~~409 gross operated horizontal wells as of ~~September~~June 30, ~~2020.~~2021. These increases were partially offset by ~~cost reduction initiatives,~~lower water handling costs, which ~~included moving multiple~~are associated with our higher level of recycling activity whereby produced water from our operated wells ~~off generators~~is recycled and then reused in our drilling and completion operations. This process results in significantly lower costs as compared to more cost-efficient electrical line-power and switching wells away from electrical submersible pumps to more reliable and lower cost gas lift, and lower variable and semi-variable costs stemming from the 6% production decline between periods.typical water disposal rates.

LOE per Boe was ~~$4.79~~$4.52 for the ~~third~~second quarter of ~~2021,~~2022, which represents an increase of ~~$0.92~~$0.42 per Boe (or ~~24%~~10%) from the ~~third~~second quarter of ~~2020.~~2021. This increase was primarily driven by per ~~BOE~~Boe increases associated with (i) higher ~~environmental and preventative maintenance costs~~electricity expenses between periods ~~as well as~~(discussed above); (ii) higher workover expense; and (iii) fixed and semi-variable costs, ~~that don’t decrease at the same rate as declines in production,~~ such as monthly ~~rental fees for compressors~~equipment rentals, repair work, labor, and ~~other equipment,~~ wellhead chemical costs, ~~and water handling costs.~~that increase at a higher rate than increases in production. These per Boe increases were partially offset by decreases in our ~~cost reduction initiatives~~water handling costs described above.

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Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended ~~September~~June 30, ~~2021~~2022 increased ~~$10.0~~$18.9 million compared to the three months ended ~~September~~June 30, ~~2020.~~2021. Severance taxes are ~~primarily~~ based on the market value of our oil and gas production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of proved developed oil and gas properties and vary across the different counties in which we operate. Severance taxes for the ~~third~~second quarter of ~~2021~~2022 increased ~~$11.1~~$17.6 million compared to the same ~~2020~~2021 period primarily due to higher oil, natural gas and NGL revenues between periods. ~~These increases were partially offset by a $1.2 million decrease in ad~~Ad valorem taxes between periods also increased $1.3 million due to ~~lower~~higher tax assessments on our oil and gas reserve values.

Severance and ad valorem taxes as a percentage of total net revenues increased to ~~6.2%~~7.3% for the ~~third quarter of 2021~~three months ended June 30, 2022 as compared to ~~5.3%~~6.8% for the same prior year ~~quarter due to~~quarter. This increase in rate was the result of a ~~greater proportion~~larger portion of our ~~commodity sales~~oil and gas volumes being ~~generated~~produced in New Mexico, which ~~has~~levies higher severance tax rates ~~in 2021. However, these rates for both periods were lower~~ than ~~our average historical rates of 7% to 8%. The lower severance and ad valorem tax rate for~~Texas, during the ~~2021 period was due to the decrease in ad valorem tax assessments discussed above, and the lower rate for the 2020 period was related to $2.2 million in tax credits we received in the third~~second quarter of ~~2020 on wells designated as “high cost gas” by the state of Texas.~~2022.

Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended ~~September~~June 30, ~~2021~~2022 increased ~~$5.0~~$6.3 million as compared to the three months ended ~~September~~June 30, ~~2020. On~~2021. Similarly, GP&T increased on a per Boe basis ~~GP&T likewise increased~~ from ~~$3.02~~$3.47 for the ~~third~~second quarter of ~~2020~~2021 to $4.03 for the ~~third~~second quarter of ~~2021.~~2022. These increases were mainly ~~related~~attributable to ~~substantially~~ higher gas plant processing costs, whose variable fee portion is based on natural gas and NGL prices, both of which increased substantially between periods as ~~these products are cost inputs into the percent-of-proceeds (“POP”)~~discussed above. This increase was partially offset by a higher portion of our 2022 oil and gas ~~plant processing fees.~~volumes being produced from our New Mexico wells, where our GP&T rates are currently lower than those in Texas.

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


		Three Months Ended September 30,					Three Months Ended June 30,
(in thousands, except per Boe data)	(in thousands, except per Boe data)	2021		2020		(in thousands, except per Boe data)	2022		2021
Depreciation, depletion and amortization	Depreciation, depletion and amortization	$	76,047	$	89,444	Depreciation, depletion and amortization	$	82,117	$	73,429
Depreciation, depletion and amortization per Boe	Depreciation, depletion and amortization per Boe	$	12.69	$	14.10	Depreciation, depletion and amortization per Boe	$	12.85	$	13.09

For the three months ended ~~September~~June 30, ~~2021,~~2022, DD&A expense amounted to ~~$76.0~~$82.1 million, ~~a decrease~~an increase of ~~$13.4~~$8.7 million over the same ~~2020~~2021 period. The primary factor contributing to ~~lower~~higher DD&A expense in ~~2021~~2022 was the ~~decrease~~increase in our ~~DD&A rates between periods, which lowered our DD&A expense by $8.5 million, while our lower~~ overall production volumes between periods, which increased DD&A expense by $10.2 million for the three months ended June 30, 2022. This was partially offset by our lower DD&A rate in the 2022 period, which decreased DD&A expense by ~~an additional $4.9~~$1.5 million ~~during the three months ended September 30, 2021.~~between periods.

Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves. DD&A per Boe was ~~$12.69~~$12.85 for the ~~third~~second quarter of ~~2021~~2022 compared to ~~$14.10~~$13.09 for the same period in ~~2020.~~2021. This decrease in DD&A rate was primarily due to ~~(i) net upward revisions in our~~the Company continuing to complete wells with low finding and development costs and high quantities of associated proved developed reserves since the ~~third~~second quarter of ~~2020 mainly~~2021.

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


	Three Months Ended June 30,
(in thousands)	2022		2021
Cash general and administrative expenses	$	12,434	$	10,126
Stock-based compensation - equity awards	6,106		4,260
Stock-based compensation - liability awards	(8,593)		14,421
General and administrative expenses	9,947		28,807

G&A expenses for the three months ended June 30, 2022 were $9.9 million compared to $28.8 million for the three months ended June 30, 2021. Lower G&A in the second quarter of 2022 was the result of a $21.2 million decrease in total stock-based compensation expense between periods. This decrease was primarily related to performance stock units granted in 2020 that are recorded at their respective fair value each balance sheet date, and such fair value decreased between periods. This decrease was slightly offset by an increase in cash G&A, which increased $2.3 million period over period due to higher ~~SEC reserve pricing, lower operating~~payroll and other personnel costs.

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Merger and integration expense. Merger and integration expense for the three months ended June 30, 2022 was $5.7 million and includes costs incurred for the pending Merger consisting primarily of legal and ~~positive well performance from our drilling and completion (“D&C”) activity during~~advisory fees. See Note 2—Business Combination for further details regarding the ~~period, and (ii) lower D&C costs per lateral foot in 2021 versus 2020.~~pending Merger.

Impairment and Abandonment Expense. During the three months ended ~~September~~June 30, ~~2021~~2022, impairment and abandonment expense was ~~$7.7~~$0.5 million as compared to ~~$19.9~~$9.2 million during the three months ended ~~September~~June 30, ~~2020 both~~2021. Both periods consist solely of ~~which related to the~~ amortization of leasehold expiration costs associated with individually insignificant unproved properties.

Exploration and Other Expenses. The following table summarizes our exploration and other expenses for the periods indicated:


		Three Months Ended September 30,					Three Months Ended June 30,
(in thousands)	(in thousands)	2021		2020		(in thousands)	2022		2021
Geological and geophysical costs	Geological and geophysical costs	$	836	$	1,055	Geological and geophysical costs	$	1,534	$	1,173
Stock-based compensation - equity awards	Stock-based compensation - equity awards	1,184		256		Stock-based compensation - equity awards	551		221
Stock-based compensation - liability awards	Stock-based compensation - liability awards	(495)		—		Stock-based compensation - liability awards	—		239
Stock-based compensation - cash settled awards		314		—

Other expenses	Other expenses	—		1,359		Other expenses	(131)		131
Exploration and other expenses	Exploration and other expenses	$	1,839	$	2,670	Exploration and other expenses	$	1,954	$	1,764

Exploration and other expenses were $2.0 million for the three months ended June 30, 2022 compared to $1.8 million for the three months ended ~~September~~June 30, ~~2021 compared to $2.7 million for the three months ended September 30, 2020.~~2021. Exploration and other expenses mainly consist of topographical studies, geographical and geophysical (“G&G”) projects, salaries and expenses of G&G personnel and includes other operating costs. The

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period over period decrease was primarily related to $1.4 million in environmental remediation costs incurred in the third quarter of 2020, which were not similarly incurred in 2021. This decrease was partially offset by an increase in total stock-based compensation costs incurred in the third quarter of 2021 related to certain restricted stock units that became fully vested as discussed below.

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

Three Months Ended September 30,
(in thousands) 2021 2020
Cash general and administrative expenses $ 12,462 $ 11,741
Stock-based compensation - equity awards 22,049 4,772
Stock-based compensation - liability awards (4,628) 487
Stock-based compensation - cash settled awards 5,865 —
Severance payments — 582
General and administrative expenses $ 35,748 $ 17,582

G&A expenses for the three months ended September 30, 2021 were $35.7 million compared to $17.6 million for the three months ended September 30, 2020. Higher G&A in the third quarter of 2021 was the result of an $18.0 million increase in total stock-based compensation expense between periods. This increase was primarily related to ~~a portion of our liability classified restricted stock units, held by certain officers (non-NEOs) and employees, becoming fully vested following a maximum return event that was triggered~~higher G&G personnel costs in the ~~third~~second quarter of 2021. These awards were settled one-third in cash ($5.9 million) and two-thirds in equity, resulting in $13.8 million of expense being recognized during the three months ended September 30, 2021. Also, there was an additional $4.4 million increase in stock-based compensation related to liability classified performance stock units that had a higher fair value as of September 30, 2021, as their fair value is required to be re-measured at each balance sheet date. Refer to ~~Note 6—Stock-Based Compensation~~ ~~for additional information regarding these awards and the maximum return event.~~

~~Other Income and Expenses.~~2022.

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


		Three Months Ended September 30,					Three Months Ended June 30,
(in thousands)	(in thousands)	2021		2020		(in thousands)	2022		2021
Credit facility	Credit facility	$	2,668	$	3,930	Credit facility	$	772	$	2,762
8.00% Senior Secured Notes due 2025	8.00% Senior Secured Notes due 2025	—		2,514		8.00% Senior Secured Notes due 2025	—		367
5.375% Senior Notes due 2026	5.375% Senior Notes due 2026	3,889		3,889		5.375% Senior Notes due 2026	3,889		3,889
6.875% Senior Notes due 2027	6.875% Senior Notes due 2027	6,125		6,125		6.875% Senior Notes due 2027	6,125		6,125
3.25% Convertible Senior Notes due 2028	3.25% Convertible Senior Notes due 2028	1,381		—		3.25% Convertible Senior Notes due 2028	1,381		1,381
Amortization of debt issuance costs and debt discount	Amortization of debt issuance costs and debt discount	1,048		1,778		Amortization of debt issuance costs and debt discount	2,734		1,040
Interest capitalized	Interest capitalized	(421)		(518)		Interest capitalized	(575)		(382)
Total	Total	$	14,690	$	17,718	Total	$	14,326	$	15,182

Interest expense decreased ~~$3.0~~$0.9 million for the three months ended ~~September~~June 30, ~~2021~~2022 as compared to the three months ended ~~September~~June 30, ~~2020~~2021 primarily due to (i) ~~$2.5~~$2.0 million in lower interest incurred on our Credit Agreement due to lower borrowings outstanding during the 2022 period, and (ii) $0.4 million in interest expense on our Senior Secured Notes due 2025 that was incurred in the ~~third~~second quarter of ~~2020~~2021 but not in the ~~2021~~2022 period, as these notes were redeemed in April ~~2021, and (ii) $1.3 million in lower interest incurred on our credit facility due to fewer borrowings outstanding during the 2021 period.~~of 2021. These decreases were partially offset by ~~interest on our Convertible Senior Notes that was~~additional debt issuance costs amortized during the second quarter of 2022 related to fees incurred for an incremental commitment letter we entered into in ~~2021 but not in 2020 due to their issuance in March 2021. Refer to~~ ~~Note 4—Long-Term Debt~~ ~~under Part I, Item I of this Quarterly Report for additional information on our senior notes and debt transactions.~~connection with the Merger.

Our weighted average borrowings outstanding under our ~~credit facility~~Credit Agreement were ~~$264.8~~$5.4 million versus ~~$389.6~~$289.8 million for the three months ended ~~September~~June 30, ~~2021~~2022 and ~~2020,~~2021, respectively. Our ~~credit facility’s~~Credit Agreement’s weighted average effective interest rate ~~(which is a LIBOR-based rate)~~ was ~~3.3%~~2.7% and ~~3.5%~~3.3% for the three months ended ~~September~~June 30, 2022 and 2021, respectively.

Gain (loss) on extinguishment of debt. During the three months ended June 30, 2021, we redeemed at par all of our $127.1 million aggregate principal amount of Senior Secured Notes outstanding. In connection with this redemption, we recorded a loss on debt extinguishment of $22.2 million related to the write-off of all unamortized debt issuance costs and ~~2020, respectively.~~debt discounts associated with these notes.

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Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding and (ii) monthly cash settlements on any closed out hedge positions during the period.

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


		Three Months Ended September 30,					Three Months Ended June 30,
(in thousands)	(in thousands)	2021		2020		(in thousands)	2022		2021
Realized cash settlement gains (losses)	Realized cash settlement gains (losses)	$	(28,796)	$	(34,486)	Realized cash settlement gains (losses)	$	(73,648)	$	(37,513)
Non-cash mark-to-market derivative gain (loss)	Non-cash mark-to-market derivative gain (loss)	(15,731)		32,518		Non-cash mark-to-market derivative gain (loss)	39,514		(17,446)
Total	Total	$	(44,527)	$	(1,968)	Total	$	(34,134)	$	(54,959)

Income Tax (Expense) Benefit. The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated:


		Three Months Ended September 30,					Three Months Ended June 30,
(in thousands)	(in thousands)	2021		2020		(in thousands)	2022		2021
Income (loss) before income taxes	Income (loss) before income taxes	$	37,124	$	(51,529)	Income (loss) before income taxes	$	233,313	$	(25,055)
Income tax (expense) benefit	Income tax (expense) benefit	—		—		Income tax (expense) benefit	(41,487)		—

Our provisions for income taxes for the three months ended ~~September~~June 30, ~~2021~~2022 and ~~2020~~2021 differs from the amounts that would be provided by applying the ~~statutory~~ U.S. federal ~~income tax~~statutory rate of 21% to pre-tax book income (loss) primarily due to (i) permanent differences, (ii) state income taxes, ~~(ii) permanent differences,~~ and (iii) any changes during the period in our deferred tax asset valuation allowance.

For the three months ended ~~September~~June 30, ~~2021,~~2022, we generated pre-tax net income of ~~$37.1~~$233.3 million ~~which reduced~~and recorded income tax expense of $41.5 million. The primary factor decreasing our ~~total net operating losses (“NOLs”) accumulated for~~income tax expense below the ~~year by this same amount. As a result~~U.S. statutory rate was the partial release of ~~the $37.1 million reduction to~~ our ~~2021 NOL position, we were able to reduce our corresponding~~ deferred tax ~~asset~~ valuation allowance ~~by $11.9 million. Conversely, f~~due to the generation of net income in the current year.

orFor the three months ended ~~September~~June 30, ~~2020,~~2021, we recognized a deferred tax asset valuation allowance of ~~$8.3~~$7.6 million against ~~NOLs~~net operating losses (“NOLs”) we generated during the ~~quarter. These changes~~quarter, and such NOLs were estimated at such time as unlikely to be realized in ~~our deferred tax asset~~future periods. The increase in the valuation allowance ~~are~~was the primary factor reducing our income tax ~~expense or~~ benefit (based on the U.S. statutory rate) to zero for the ~~third~~second quarter of ~~2021 and 2020, respectively,~~ ~~to zero.~~ 2021.

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~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~2022 Compared to ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021


		Nine Months Ended September 30,				Increase/(Decrease)					Six Months Ended June 30,				Increase/(Decrease)
		2021		2020		$		%			2022		2021		$		%
Net revenues (in thousands):	Net revenues (in thousands):									Net revenues (in thousands):
Oil sales	Oil sales	$	512,278	$	363,571	$	148,707	41	%	Oil sales	$	612,358	$	310,831	$	301,527	97	%
Natural gas sales	Natural gas sales	106,266		29,052		77,214		266	%	Natural gas sales	107,048		62,466		44,582		71	%
NGL sales	NGL sales	94,929		39,756		55,173		139	%	NGL sales	100,525		51,671		48,854		95	%
Oil and gas sales	Oil and gas sales	$	713,473	$	432,379	$	281,094	65	%	Oil and gas sales	$	819,931	$	424,968	$	394,963	93	%

Average sales prices:	Average sales prices:									Average sales prices:
Oil (per Bbl)	Oil (per Bbl)	$	60.05	$	34.86	$	25.19	72	%	Oil (per Bbl)	$	97.42	$	57.08	$	40.34	71	%
Effect of derivative settlements on average price (per Bbl)	Effect of derivative settlements on average price (per Bbl)	(10.12)		(3.58)		(6.54)		(183)	%	Effect of derivative settlements on average price (per Bbl)	(15.03)		(11.12)		(3.91)		(35)	%
Oil net of hedging (per Bbl)	Oil net of hedging (per Bbl)	$	49.93	$	31.28	$	18.65	60	%	Oil net of hedging (per Bbl)	$	82.39	$	45.96	$	36.43	79	%

Average NYMEX price for oil (per Bbl)	Average NYMEX price for oil (per Bbl)	$	64.82	$	38.37	$	26.45	69	%	Average NYMEX price for oil (per Bbl)	$	101.37	$	61.95	$	39.42	64	%
Oil differential from NYMEX	Oil differential from NYMEX	(4.77)		(3.51)		(1.26)		(36)	%	Oil differential from NYMEX	(3.95)		(4.87)		0.92		19	%

Natural gas (per Mcf)	Natural gas (per Mcf)	$	3.44	$	0.93	$	2.51	270	%	Natural gas (per Mcf)	$	5.13	$	3.13	$	2.00	64	%
Effect of derivative settlements on average price (per Mcf)	Effect of derivative settlements on average price (per Mcf)	(0.09)		(0.13)		0.04		31	%	Effect of derivative settlements on average price (per Mcf)	(1.06)		0.01		(1.07)		(10,700)	%
Natural gas net of hedging (per Mcf)	Natural gas net of hedging (per Mcf)	$	3.35	$	0.80	$	2.55	319	%	Natural gas net of hedging (per Mcf)	$	4.07	$	3.14	$	0.93	30	%

Average NYMEX price for natural gas (per Mcf)	Average NYMEX price for natural gas (per Mcf)	$	3.53	$	1.82	$	1.71	94	%	Average NYMEX price for natural gas (per Mcf)	$	6.00	$	3.15	$	2.85	90	%
Natural gas differential from NYMEX	Natural gas differential from NYMEX	(0.09)		(0.89)		0.80		90	%	Natural gas differential from NYMEX	(0.87)		(0.02)		(0.85)		(4,250)	%

NGL (per Bbl)	NGL (per Bbl)	$	33.98	$	11.50	$	22.48	195	%	NGL (per Bbl)	$	46.74	$	30.10	$	16.64	55	%

Net production:	Net production:									Net production:
Oil (MBbls)	Oil (MBbls)	8,531		10,429		(1,898)		(18)	%	Oil (MBbls)	6,286		5,446		840		15	%
Natural gas (MMcf)	Natural gas (MMcf)	30,933		31,209		(276)		(1)	%	Natural gas (MMcf)	20,866		19,956		910		5	%
NGL (MBbls)	NGL (MBbls)	2,794		3,458		(664)		(19)	%	NGL (MBbls)	2,151		1,717		434		25	%
Total (MBoe)(1)	Total (MBoe)(1)	16,479		19,088		(2,609)		(14)	%	Total (MBoe)(1)	11,914		10,488		1,426		14	%

Average daily net production:	Average daily net production:									Average daily net production:
Oil (Bbls/d)	Oil (Bbls/d)	31,246		38,061		(6,815)		(18)	%	Oil (Bbls/d)	34,729		30,086		4,643		15	%
Natural gas (Mcf/d)	Natural gas (Mcf/d)	113,305		113,900		(595)		(1)	%	Natural gas (Mcf/d)	115,280		110,253		5,027		5	%
NGLs (Bbls/d)	NGLs (Bbls/d)	10,233		12,619		(2,386)		(19)	%	NGLs (Bbls/d)	11,881		9,484		2,397		25	%
Total (Boe/d)(1)	Total (Boe/d)(1)	60,363		69,664		(9,301)		(13)	%	Total (Boe/d)(1)	65,824		57,945		7,879		14	%

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

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Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 were ~~$281.1~~$395.0 million, or ~~65%~~93%, higher than total net revenues for the ~~nine~~six months ended ~~September~~June 30, ~~2020.~~2021. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

Average realized sales prices for oil, residue gas and NGLs increased for the first ~~nine months~~half of ~~2021~~2022 compared to the same ~~2020~~2021 period by ~~72%~~71%, ~~270%~~64%, and ~~195%~~55%, respectively. The ~~72%~~71% increase in the average realized oil price was mainly the result of higher ~~(69%~~(64%) NYMEX crude prices between periods, ~~which was minimally offset by wider~~as well as improved oil differentials ($~~1.26~~0.92 per Bbl ~~wider)~~narrower). The average realized sales price of natural gas increased ~~270%~~64% due to higher ~~(94%~~(90%) average NYMEX gas prices between periods, ~~as well as improved~~partially offset by wider gas differentials ~~(by $0.80~~($0.85 per ~~Mcf)~~Mcf wider). The ~~195%~~55% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products for the first ~~nine months~~half of ~~2021~~2022 compared to the first ~~nine months~~half of ~~2020.~~2021. The market prices for oil, natural gas and NGLs have all been impacted by ~~higher~~ global ~~demand~~supply constraints for oil and gas ~~compared to the first nine months of 2020, when prices decreased significantly beginning in March 2020~~throughout 2021 and 2022, as ~~a result of~~well as increasing demand worldwide as global economies emerge from COVID-19 era lockdowns and ~~supply disruptions from the Russia-Saudi oil price war~~restrictions, as discussed in the market conditions section above. Additionally, the first quarter 2021 realized price for natural gas in the Permian Basin was impacted by Winter Storm Uri, which caused gas pipeline and supply disruptions and resulted in significant increases in Permian natural gas prices during this period.

Net production volumes for oil, natural gas, and NGLs ~~decreased 18%~~increased 15%, 1%5%, and ~~19%~~25%, respectively, between periods. The oil production volume ~~decrease was primarily related to normal production decline across~~increase resulted from our ~~existing wells and temporary shut-ins of our wells during mid-February as a result of Winter Storm Uri. Oil volume declines~~successful drilling program in the ~~first nine months~~Delaware Basin. Since the second quarter of 2021, ~~were additionally impacted by less drilling and completion activity over the past 12 months as a result of depressed oil and gas prices, which resulted in only 33~~we placed 50 wells ~~being placed~~ on production, ~~since the third quarter of 2020. This~~which added ~~2,078~~2,788 MBbls of net oil production to the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 as compared to 5828 wells brought online since the ~~third~~second quarter of ~~2019~~2020 that added ~~4,036~~1,214 MBbls of net oil production to the ~~nine~~six months ended ~~September~~June 30, ~~2020.~~2021. These oil volume increases were partially offset by normal production decline 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. However, ~~during the 2021 period,~~ the main processor of our raw gas operated in ~~full ethane-rejection,~~partial ethane-recovery during the first half of 2022, as compared to operating in ~~partial ethane-recovery~~full ethane-rejection during the ~~same 2020 period.~~ ~~Additionally, the amount of gas flared as a percentage of wellhead gas produced was significantly less during the first~~ ~~nine months~~ of 2021 ~~as compared to the same 2020 period.~~ ~~Both of these factors combined~~period, and this resulted in ~~an increase in the amount of~~fewer natural gas ~~recovered~~volumes and ~~sold~~more NGLs being recovered from our wet gas stream ~~between periods, while the variations in ethane-rejection resulted in fewer NGLs being recovered~~ during the ~~2021~~2022 period.

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


		Nine Months Ended September 30,						Increase/(Decrease)						Six Months Ended June 30,						Increase/(Decrease)
		2021			2020			Change			%			2022			2021			Change			%
Operating costs (in thousands):	Operating costs (in thousands):												Operating costs (in thousands):
Lease operating expenses	Lease operating expenses	$	77,522		$	83,021		$	(5,499)		(7)	%	Lease operating expenses	$	57,634		$	48,837		$	8,797		18	%
Severance and ad valorem taxes	Severance and ad valorem taxes	46,167			30,108			16,059			53	%	Severance and ad valorem taxes	59,746			28,367			31,379			111	%
Gathering, processing and transportation expenses	Gathering, processing and transportation expenses	64,283			53,353			10,930			20	%	Gathering, processing and transportation expenses	47,647			40,119			7,528			19	%
Operating cost metrics:	Operating cost metrics:												Operating cost metrics:
Lease operating expenses (per Boe)	Lease operating expenses (per Boe)	$	4.70		$	4.35		$	0.35		8	%	Lease operating expenses (per Boe)	$	4.84		$	4.66		$	0.18		4	%
Severance and ad valorem taxes (% of revenue)	Severance and ad valorem taxes (% of revenue)	6.5		%	7.0		%	(0.5)		%	(7)	%	Severance and ad valorem taxes (% of revenue)	7.3		%	6.7		%	0.6		%	9	%
Gathering, processing and transportation expenses (per Boe)	Gathering, processing and transportation expenses (per Boe)	$	3.90		$	2.80		$	1.10		39	%	Gathering, processing and transportation expenses (per Boe)	$	4.00		$	3.83		$	0.17		4	%

Lease Operating Expenses. LOE for the ~~nine~~six months ended ~~September~~June 30, ~~2021 decreased $5.5~~2022 increased $8.8 million as compared to the ~~nine~~six months ended ~~September~~June 30, ~~2020. Lower~~2021. Higher LOE for the first ~~nine months~~half of ~~2021~~2022 was primarily related to (i) a ~~$3.9~~$2.2 million ~~decrease~~increase in electricity costs between periods due to electricity credits received during 2021 related Winter Storm Uri that were not similarly received in 2022; (ii) an increase in workover expense of $1.8 million between periods; ~~(ii) decreases in electricity costs as a result of credits realized in the current year period related to Winter Storm Uri;~~and (iii) lower well operating expenses due to cost reduction initiatives, which included moving multiple wells off generator to more cost-efficient electrical line-power and switching wells away from electric submersible pumps to more reliable and lower cost gas lift; and (iv) lower variable and semi-variable costs stemming from the 14% production decline between periods. These decreases were partially offset by higher ~~chemical costs, environmental expenses and preventative maintenance costs, and additional~~ fixed and variable costs associated with our higher well count, which increased to ~~413~~435 gross operated horizontal wells as of ~~September~~June 30, ~~2021~~2022 from ~~387~~409 gross operated horizontal wells as of ~~September~~June 30, ~~2020.~~2021. These increases were partially offset by lower water handling costs, which are associated with our higher level of recycling activity whereby produced water from our operated wells is recycled and then reused in our drilling and completion operations. This process results in significantly lower costs as compared to typical water disposal rates.

LOE per Boe was ~~$4.70~~$4.84 for the ~~nine~~six months ended ~~September~~June 30, ~~2021,~~2022, which represents an increase of ~~$0.35~~$0.18 per Boe (or 8%4%) from the comparable ~~2020~~2021 period. This increase was primarily driven by per ~~BOE cost~~Boe increases associated with (i) higher electricity expenses between periods ~~associated with~~(discussed above); (ii) higher workover expense; and (iii) fixed and semi-variable costs, ~~that don’t decrease at the same rate as declines in production,~~ such as monthly ~~rental fees for compressors~~equipment rentals, repair work, labor, and ~~other equipment,~~ wellhead chemical costs, ~~and water handling costs. In addition, environmental expenses and preventative maintenance costs were~~that increase at a higher ~~for the nine months ended September 30, 2021 as compared to the same prior year~~

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~~period.~~rate than increases in production. These per Boe increases were partially offset by ~~the lower level of workover activity~~decreases in ~~the 2021 period, decreased electricity~~our water handling costs ~~and the cost reduction initiatives we have undertaken, as discussed~~described above.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 increased ~~$16.1~~$31.4 million compared to the ~~nine~~six months ended ~~September~~June 30, ~~2020.~~2021. Severance taxes are ~~primarily~~ based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Severance taxes for the first ~~nine months~~half of ~~2021~~2022 increased ~~$19.6~~$29.0 million compared to the same ~~2020~~2021 period primarily due to higher oil, natural gas and NGL revenues between periods. ~~These increases were partially offset by a $3.6 million decrease in ad~~Ad valorem taxes between periods also increased $2.4 million due to ~~lower~~higher tax assessments on our oil and gas reserve values.

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Severance and ad valorem taxes as a percentage of total net revenues ~~decreased~~increased to ~~6.5%~~7.3% for the first ~~nine months~~half of ~~2021~~2022 as compared to ~~7.0%~~6.7% for the same ~~2020 period as a~~2021 period. This increase in rate was the result of a larger portion of our oil and gas volumes being produced in New Mexico, which levies higher severance tax rates than Texas, during the ~~lower 2021 ad valorem tax assessments discussed above.~~first half of 2022.

Gathering, Processing and Transportation Expenses. GP&T for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 increased ~~$10.9~~$7.5 million compared to the ~~nine~~six months ended ~~September~~June 30, ~~2020. On~~2021. Similarly, GP&T on a per Boe basis ~~GP&T likewise~~ increased from ~~$2.80~~$3.83 for the first ~~nine months~~half of ~~2020~~2021 to ~~$3.90~~$4.00 for the same ~~2021~~2022 period. These increases were mainly attributable to ~~(i)~~ higher gas plant processing costs, whose ~~POP~~variable fee portion is based on natural gas and NGL prices, both of which increased substantially between periods as discussed ~~above, and (ii)~~above. This increase was partially offset by a ~~$2.1 million decrease in reimbursements received from third parties for their usage~~higher portion of our ~~available firm transport capacity.~~2022 oil and gas volumes being produced from our New Mexico wells, where our GP&T rates are currently lower than those in Texas.

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


		Nine Months Ended September 30,					Six Months Ended June 30,
(in thousands, except per Boe data)	(in thousands, except per Boe data)	2021		2020		(in thousands, except per Boe data)	2022		2021
Depreciation, depletion and amortization	Depreciation, depletion and amortization	$	213,259	$	283,722	Depreciation, depletion and amortization	$	153,126	$	137,212
Depreciation, depletion and amortization per Boe	Depreciation, depletion and amortization per Boe	$	12.94	$	14.86	Depreciation, depletion and amortization per Boe	$	12.85	$	13.08

For the ~~nine~~six months ended ~~September~~June 30, ~~2021,~~2022, DD&A expense amounted to ~~$213.3~~$153.1 million, ~~a decrease~~an increase of ~~$70.5~~$15.9 million over the same ~~2020~~2021 period. The primary factor contributing to ~~lower~~higher DD&A expense in ~~2021~~2022 was the ~~decrease~~increase in our overall production volumes between periods, which ~~lowered~~increased DD&A expense by ~~$38.8~~$18.6 million during the first ~~nine months~~half of ~~2021,~~2022, while lower DD&A rates between periods decreased DD&A expense by ~~$31.7~~$2.7 million ~~during~~for the ~~nine~~six months ended ~~September~~June 30, ~~2021.~~2022.

Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves. DD&A per Boe was ~~$12.94~~$12.85 for the first ~~nine months~~half of ~~2021~~2022 compared to ~~$14.86~~$13.08 for the same period in ~~2020.~~2021. This decrease in DD&A rate was primarily due to ~~(i)~~ the ~~proved property impairment recognized in the first quarter~~Company continuing to complete wells with low finding and development costs and high quantities of ~~2020, which lowered the carrying value of our depletion base by $591.8 million; (ii) net upward revisions in our~~associated proved developed reserves since the ~~third~~second quarter of ~~2020 mainly~~2021.

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


	Six Months Ended June 30,
(in thousands)	2022		2021
Cash general and administrative expenses	$	24,203	$	20,758
Stock-based compensation expense - equity awards	11,220		8,637
Stock-based compensation expense - liability awards	5,127		24,668
General and administrative expenses	$	40,550	$	54,063

G&A expenses for the six months ended June 30, 2022 were $40.6 million compared to $54.1 million for the six months ended June 30, 2021. Lower G&A in the first half of 2022 was the result of a $17.0 million decrease in total stock-based compensation expense between periods. This decrease was primarily related to performance stock units granted in 2020 that are recorded at their respective fair value each balance sheet date, and such fair value decreased between periods. This decrease was slightly offset by higher ~~SEC reserve pricing, lower operating~~cash G&A which increased $3.4 million period over period due to higher payroll and other personnel cost increases.

Merger and integration expense. Merger and integration expense for the six months ended June 30, 2022 was $5.7 million and includes costs incurred for the pending Merger consisting primarily of legal and ~~positive well performance from our D&C activity during~~advisory fees. See Note 2—Business Combination for further details regarding the ~~period; and (iii) lower D&C costs per lateral foot in 2021 versus 2020.~~pending Merger.

Impairment and Abandonment Expense. During the ~~nine~~six months ended ~~September~~June 30, ~~2021, $26.1 million of~~2022, impairment and abandonment expense was ~~incurred related~~$3.1 million as compared to $18.4 million during the ~~amortization of leasehold expiration costs associated with individually insignificant unproved properties. During the nine~~six months ended ~~September~~June 30, ~~2020, impairment and abandonment expense was $650.6 million and consisted~~2021. Both periods consist solely of ~~(i) a $591.8 million non-cash impairment of our proved oil and gas properties as a result of depressed NYMEX oil and gas forward curves as of March 31, 2020; and (ii) $58.8 million related to the~~ amortization of leasehold expiration costs associated with individually insignificant unproved properties.

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Exploration and Other Expenses. The following table summarizes our exploration and other expenses for the periods indicated:


		Nine Months Ended September 30,					Six Months Ended June 30,
(in thousands)	(in thousands)	2021		2020		(in thousands)	2022		2021
Geological and geophysical costs	Geological and geophysical costs	$	2,622	$	4,129	Geological and geophysical costs	$	3,237	$	1,786
Rig termination fees		—		3,046
Severance payments		—		722
Stock-based compensation - equity awards	Stock-based compensation - equity awards	1,613		1,230		Stock-based compensation - equity awards	982		429
Stock-based compensation - liability awards	Stock-based compensation - liability awards	(89)		—		Stock-based compensation - liability awards	—		406
Stock-based compensation - cash settled awards		314		—
Other expenses	Other expenses	238		1,603		Other expenses	42		238
Exploration and other expenses	Exploration and other expenses	$	4,698	$	10,730	Exploration and other expenses	$	4,261	$	2,859

Exploration and other expenses were ~~$4.7~~$4.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 compared to ~~$10.7~~$2.9 million for the same prior year period. Exploration and other expenses mainly consist of topographical studies, G&G projects, salaries and expenses of G&G personnel and includes other operating costs. The period over period decrease was primarily due to (i) rig termination fees that went from $3.0 million in the first nine months of 2020 (when we reduced our drilling program from five rigs to none) to zero in the 2021 period; (ii) $1.2 million in lower ongoing G&G personnel costs related to the 2020 workforce reduction; (iii) $0.7 million in severance payments to G&G employees in the 2020 period that did not reoccur in the 2021 period; and (iv) $1.4 million in environmental remediation costs incurred in the first nine months of 2020, which were not similarly incurred in 2021. These decreases were partially offset by an increase in total stock-based compensation costs incurred during the nine months ended September 30, 2021 related to restricted stock units that became fully vested during the period as discussed below.

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

Nine Months Ended September 30,
(in thousands) 2021

2020
Cash general and administrative expenses $ 33,220 $ 35,559
Stock-based compensation expense - equity awards 30,686 14,934
Stock-based compensation expense - liability awards 20,040 487
Stock-based compensation - cash settled awards 5,865 —
Severance payments — 3,466
General and administrative expenses $ 89,811 $ 54,446

G&A expenses for the nine months ended September 30, 2021 were $89.8 million compared to $54.4 million for the nine months ended September 30, 2020. Higher G&A in the first nine months of 2021 was the result of a $41.2 million increase in total stock-based compensation expense between periods. This increase was primarily related to ~~a portion of our liability classified restricted stock units, held by certain officers (non-NEOs) and employees, becoming fully vested following a maximum return event that was triggered~~higher G&G personnel costs in the ~~third quarter~~second half of 2021. These awards were settled one-third in cash ($5.9 million) and two-thirds in equity, resulting in $21.4 million of expense being recognized during the nine months ended September 30, 2021. Also, there was an additional $21.5 million increase in total stock-based compensation related to liability classified performance stock units that had a higher fair value as of September 30, 2021, as their fair value is required to be re-measured at each balance sheet date. Refer to ~~Note 6—Stock-Based Compensation~~ for additional information regarding these awards and the maximum return event. These increases were partially offset by (i) $3.5 million in severance payments to G&A employees in the 2020 period that did not reoccur in the first nine months of 2021; and (ii) $2.3 million in lower payroll and other personnel related costs as a result of our lower G&A headcount between periods.

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2022.

Other Income and Expenses.

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


		Nine Months Ended September 30,					Six Months Ended June 30,
(in thousands)	(in thousands)	2021		2020		(in thousands)	2022		2021
Credit facility	Credit facility	$	8,745	$	9,256	Credit facility	$	1,649	$	6,077
8.00% Senior Secured Notes due 2025	8.00% Senior Secured Notes due 2025	2,908		3,643		8.00% Senior Secured Notes due 2025	—		2,908
5.375% Senior Notes due 2026	5.375% Senior Notes due 2026	11,667		13,995		5.375% Senior Notes due 2026	7,778		7,778
6.875% Senior Notes due 2027	6.875% Senior Notes due 2027	18,375		22,243		6.875% Senior Notes due 2027	12,250		12,250
3.25% Convertible Senior Notes due 2028	3.25% Convertible Senior Notes due 2028	2,934		—		3.25% Convertible Senior Notes due 2028	2,762		1,553
Amortization of debt issuance costs and debt discount	Amortization of debt issuance costs and debt discount	3,935		4,112		Amortization of debt issuance costs and debt discount	4,226		2,887
Interest capitalized	Interest capitalized	(1,207)		(1,739)		Interest capitalized	(1,185)		(786)
Total	Total	$	47,357	$	51,510	Total	$	27,480	$	32,667

Interest expense was ~~$4.2~~$5.2 million lower for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 compared to the same ~~2020~~2021 period mainly due to (i) ~~$6.2~~$4.4 million in lower interest incurred on our ~~Senior Unsecured Notes~~Credit Agreement due to lower borrowings outstanding during the ~~2021~~2022 period, ~~as $110.6 million of the Senior Notes due 2026~~ and ~~$143.7 million of the Senior Notes due 2027 were extinguished in our debt exchange transaction in May 2020;~~ (ii) ~~$0.7~~$2.9 million in decreased interest expense on our Senior Secured Notes due 2025 that were ~~issued in May of 2020 and then subsequently~~ redeemed in April of ~~2021; and (iii) $0.5 million in lower interest expense incurred on our credit facility due to fewer borrowings outstanding during the 2021 period.~~2021. These decreases were partially offset by ~~$2.9 million~~(i) additional debt issuance costs amortized during the six months ended June 30, 2022 related to fees incurred for an incremental commitment letter we entered into in connection with the Merger, and (ii) interest ~~incurred~~ on our Convertible Senior Notes that ~~were issued~~was incurred in 2022 but only partially during the 2021 period due to their issuance in March of 2021. ~~Refer to~~ ~~Note 4—Long-Term Debt~~ ~~under Part I, Item I of this Quarterly Report for additional information on our senior notes and debt transactions.~~

Our weighted average borrowings outstanding under our ~~credit facility~~Credit Agreement were ~~$294.6~~$16.5 million ~~and $322.3~~versus $310.2 million for the first ~~nine months~~half of ~~2021~~2022 and ~~2020,~~2021, respectively. Our ~~credit facility’s~~Credit Agreement’s weighted average effective interest rate ~~(which is a LIBOR-based rate)~~ was ~~3.3%~~2.9% and ~~3.2%~~3.4% for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 and ~~2020,~~2021, respectively.

Gain (loss) on extinguishment of debt. During the ~~nine~~six months ended ~~September~~June 30, 2021, we redeemed at par all of our $127.1 million aggregate principal amount of Senior Secured Notes outstanding. In connection with this ~~redemptions,~~redemption, we recorded a loss on debt extinguishment of $22.2 million related to the write-off of all unamortized debt issuance costs and debt discounts associated with these notes.

A gain of $143.4 million was recognized during the nine months ended September 30, 2020 related to our 2020 debt exchange transaction. This gain was determined based on the difference between the carrying value of the Senior Unsecured Notes extinguished less the fair value of our newly issued Senior Secured Notes on their date of issuance. Refer to ~~Note 4—Long-Term Debt~~ ~~for additional information regarding the debt extinguishment transactions discussed above.~~

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


		Nine Months Ended September 30,					Six Months Ended June 30,
(in thousands)	(in thousands)	2021		2020		(in thousands)	2022		2021
Realized cash settlement gains (losses)	Realized cash settlement gains (losses)	$	(89,195)	$	(41,433)	Realized cash settlement gains (losses)	$	(116,526)	$	(60,399)
Non-cash mark-to-market derivative gain (loss)	Non-cash mark-to-market derivative gain (loss)	(61,490)		1,103		Non-cash mark-to-market derivative gain (loss)	(47,131)		(45,759)
Total	Total	$	(150,685)	$	(40,330)	Total	$	(163,657)	$	(106,158)

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Income Tax (Expense) Benefit. The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated:

Nine Months Ended September 30,
(in thousands) 2021 2020
Income (loss) before income taxes $ (22,576) $ (681,668)
Income tax (expense) benefit — 85,124

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	Six Months Ended June 30,
(in thousands)	2022		2021
Income (loss) before income taxes	$	255,891	$	(59,700)
Income tax (expense) benefit	(48,263)		—

Our provisions for income taxes for the first ~~nine months~~half of ~~2021~~2022 and ~~2020~~2021 differs from the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book income (loss) primarily due to (i) state income taxes; (ii) permanent differences; and (iii) any changes during the period in our deferred tax asset valuation allowance.

For the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 we generated pre-tax net income of $255.9 million and ~~2020,~~recorded income tax expense of $48.3 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the partial release of our deferred tax valuation allowance due to the generation of net income in the current year.

For the six months ended June 30, 2021, we recognized deferred tax asset valuation allowances of ~~$8.1~~$20.0 million ~~and $58.0 million, respectively,~~ against ~~net operating losses (“NOLs”)~~NOLs we generated during ~~those respective periods,~~the period, and such NOLs ~~are~~were estimated at such time as unlikely to be realized in future periods. ~~These increases~~The increase in our valuation allowance ~~were~~was the primary factor reducing our income tax benefit (based on the U.S. statutory rate) ~~recognized in each respective period~~ to zero for the first ~~nine~~six months of ~~2021 and to $85.1 million for the first nine months of 2020.~~2021.

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Liquidity and Capital Resources

Overview

Our drilling and completion 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, proceeds from offerings of debt or equity securities, or proceeds from the sale of oil and gas properties. ~~Future~~Our future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability 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~~six months ended ~~September~~June 30, ~~2021:~~2022:


(in millions)	~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~2022
Drilling, completion and facilities	$	~~227.8~~248.4
Infrastructure, land and other	~~7.2~~6.9

Total capital expenditures incurred	$	~~235.0~~255.3

We continually evaluate our capital needs and compare them to our capital resources. We operated a two-rig drilling program during the first ~~nine months~~half of ~~2021 and plan to continue with two rigs for the remainder of the year.~~2022. We expect our total capex budget for ~~2021~~2022 on a stand alone basis to be between ~~$300~~$365 million to ~~$315~~$425 million, of which ~~$290~~$350 million to ~~$305~~$400 million is allocated to drilling, completion and facilities activity. We funded our capital expenditures for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 entirely from cash flows from operations, and we expect to fund the remainder of our ~~2021~~stand alone 2022 capex budget entirely from cash flows from operations as well, given our anticipated level of oil and gas production, ~~together with~~current commodity prices and our commodity hedge positions in place. We ~~were~~generated free cash flow ~~positive~~ during the first ~~nine months~~half of ~~2021~~2022 such that we were able to pay down ~~approximately $105~~all of our borrowings under our Credit Agreement during the period.

In May 2022, we announced the pending Merger with Colgate that is expected close in the third quarter of 2022. If the Merger closes as expected, our 2022 operational plans and sources and use of capital, among others things, as a combined entity will change, and such changes are expected to include (i) the Company assuming $1.0 billion of Colgate’s senior notes and Colgate’s credit facility borrowings outstanding at closing, which will be refinanced under CRP’s Credit Agreement, (ii) potential borrowings under CRP’s Credit Agreement to fund some portion of the $525 million in ~~borrowings (excluding~~cash Merger consideration due at closing, and (iii) the funding of additional transaction costs yet to be incurred related to the Merger.

In February 2022, our Board of Directors authorized the Repurchase Program to acquire up to $350 million of our outstanding Common Stock. We intend to use the Repurchase Program to reduce our shares of Common Stock outstanding and plan to fund these share repurchases with cash on hand and cash flows from operations. Such repurchases would be made at terms and prices determined by us based upon prevailing market conditions, applicable legal requirements, available liquidity, compliance with our debt ~~refinancing~~and other agreements and other factors. Due to restrictions related to the Merger, we have been unable to make or initiate any share repurchases under the Repurchase Program since the announcement and therefore, we will not be able to begin repurchasing our shares until the pending Merger closes or is otherwise terminated. In addition, we may, from time to time, seek to retire or purchase our outstanding senior notes through cash purchases and/or exchanges for debt in open-market purchases, privately negotiated transactions discussed below) under our credit agreement during the period, and based upon current commodity prices, we expect to continue to pay down borrowings from free cash flow generation during the remainder of 2021.or otherwise.

Because we are the operator of a high percentage of our acreage, we can control the amount and timing of our capital expenditures. We can choose to defer or accelerate a portion of our planned capex depending on a variety of factors, including but not limited to: 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; property or land acquisition costs; and the level of participation by other working interest owners.

We cannot ensure that cash flows from operations will be available or other sources of needed capital on acceptable terms or at all. Further, our ability to access the public or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control.

~~Moreover, to manage our future maturities, lower interest expense, and improve our liquidity position, we issued 3.25% Convertible Senior Notes in March 2021, which resulted in net proceeds~~

Table of $163.6 million. The proceeds were used to repay borrowing outstanding under CRP’s revolving credit facility and to fund the cost of entering into capped call spread transactions of $14.7 million. In April 2021, we redeemed at par all of our 2025 senior secured notes ($127.1 million) that bore interest at 8% per year and paid accrued interest of $3.8 million on these notes, which was the intended use of proceeds from the Convertible Senior Notes offering. As a result of this refinancing transaction, we able to reduce net borrowings outstanding under CRP’s revolving credit facility by approximately $20 million.Contents

Analysis of Cash Flow Changes

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

Nine Months Ended September 30,
(in thousands) 2021 2020
Net cash provided by operating activities $ 333,132 $ 130,232
Net cash used in investing activities (216,318) (308,009)
Net cash (used in) provided by financing activities (117,626) 172,752

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	Six Months Ended June 30,
(in thousands)	2022		2021
Net cash provided by operating activities	$	455,099	$	179,625
Net cash used in investing activities	(228,603)		(127,076)
Net cash used in financing activities	(34,784)		(53,644)

For the ~~nine~~six months ended ~~September~~June 30, ~~2021,~~2022, we generated ~~$333.1~~$455.1 million of cash from operating activities, an increase of ~~$202.9~~$275.5 million from the same period in ~~2020.~~2021. Cash provided by operating activities increased primarily due to higher realized prices for all commodities, ~~lower lease operating expenses, lower exploration expense,~~higher production volumes, decreased cash interest costs, and the timing of our supplier payments during the ~~nine~~six months ended ~~September~~June 30, ~~2021.~~2022. These increasing factors were partially offset by ~~lower production volumes,~~ higher lease operating expenses, GP&T, ~~and~~cash G&A, severance and ad valorem ~~costs,~~taxes, cash settlement losses on derivatives, and the timing of our receivable collections ~~and cash settlement losses from derivatives~~ for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 as compared to the same ~~2020~~2021 period. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and on fluctuations in our operating ~~expenses~~costs between periods.

During the ~~nine~~six months ended ~~September~~June 30, 2022, cash flows from operating activities were used to finance $224.0 million of drilling and development cash expenditures and repay net borrowings of $25.0 million under our Credit Agreement.

During the six months ended June 30, 2021, cash flows from operating activities and net proceeds from the issuance of the Convertible Senior Notes (defined below) were used to finance ~~$215.4~~$126.7 million of drilling and development cash expenditures, repay net borrowings of ~~$125.0~~$75.0 million under our credit facility, redeem $127.1 million of our 2025 senior secured notes outstanding and to fund $14.7 million in capped call spread transactions.

During the nine months ended September 30, 2020, cash flows from operating activities, cash on hand, and net borrowings of $180.0 million under our credit facility were used to finance $300.7 million of drilling and development cash expenditures, to fund $7.7 million in oil and gas property acquisitions, and to finance $6.7 million of debt issuance and exchange costs.

Credit Agreement

On February 18, 2022, CRP ~~our consolidated subsidiary, has a credit agreement~~entered into an amended and restated five-year secured Credit Agreement with a syndicate of banks, ~~that provides for a five-year secured revolving~~which replaced our previous credit facility ~~maturing on~~that was set to mature in May ~~4, 2023 (the “Credit Agreement”).~~of 2023. The Credit Agreement increased our elected commitments to $750 million, increased our borrowing base to $1.15 billion and extended the maturity of the Credit Agreement to February 2027. As of ~~September~~June 30, ~~2021, we~~2022, the Company had ~~$205.0 million in~~no borrowings outstanding and ~~$488.5~~$744.2 million in available borrowing capacity, which was net of ~~$6.5~~$5.8 million in letters of ~~credit.~~ credit outstanding, under its new facility.

The ~~borrowing base had previously been reduced by an~~Credit Agreement provides for, among other things, the ability to repurchase outstanding shares of Common Stock and junior debt, subject to certain leverage and elected commitment availability ~~blocker of $31.8 million, however,~~conditions and subject to the blocker was removed as a result of the Senior Secured Note redemption discussed above. In connection with the Credit Agreement’s fall 2021 semi-annual borrowing base redetermination, the borrowing base and amount of elected commitments were reaffirmed at $700.0 million.

~~CRP’s~~requirement that such repurchases are funded from our free cash flow. The Credit Agreement contains restrictive covenants that limit ~~its~~our ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or ~~declare dividends; (v)~~redeem junior debt; (vi) enter into commodity hedges exceeding a specified percentage of our expected production; ~~(vi)~~(vii) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; ~~(vii)~~(viii) incur liens; ~~(viii)~~(ix) sell assets; and ~~(ix)~~(x) engage in transactions with affiliates.

~~CRP’s~~The Credit Agreement also requires usCRP to maintain compliance with the following financial ratios:

(i) a current ratio, which is the ratio of CRP’s consolidated current assets (including an add back of unused commitments under ~~its~~the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding ~~any~~the current portion of long-term debt ~~due~~ under the ~~credit agreement~~Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and

~~(iii) a leverage ratio, as defined with~~ the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the ~~rolling~~prior four fiscal quarter period. Pursuant to the Q2 2020 Amendments, the leverage ratio is suspended until March 31, 2022, at which time, the ratio may not exceed 5.00 to 1.00, with such maximum ratio declining at a ratequarters, of ~~0.25 for each succeeding quarter until March 31, 2023 when the ratio is set at~~ not greater than ~~4.0~~3.5 to 1.0.

CRP was in compliance with the covenants and the applicable financial ratios described above as of ~~September~~June 30, ~~2021~~2022 and through the filing of this Quarterly Report.

On July 15, 2022, CRP and the Company entered into the Amendment to our Credit Agreement. The Amendment, among other things, waives compliance with certain restrictive covenants and provides the lenders’ consent to a planned Pre-Merger Reorganization (as defined within the Amendment) in order to enable the Merger. In addition, the Amendment increases the elected commitments under the Credit Agreement to $1.5 billion from $750 million and the borrowing base to $2.5 billion from $1.15 billion. The Amendment is subject to and effective as of the closing date of the Merger and will be terminated if the Merger has not occurred prior to November 30, 2022.

For further information on the Credit Agreement, refer to Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report.

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Convertible Senior Notes

On March 19, 2021, CRP issued $150.0 million ~~in aggregate principal amount~~ of ~~Convertible~~3.25% senior unsecured convertible notes due 2028 (the “Convertible Senior ~~Notes.~~Notes”). On March 26, 2021, CRP issued an additional $20.0 million of Convertible Senior Notes pursuant to the exercise of the underwriters’ over-allotment option to purchase additional notes. ~~The Convertible~~These issuances resulted in aggregate net proceeds to CRP of $163.6 million, which were used to repay borrowings outstanding under the Credit Agreement and to fund the cost of entering into capped call spread transactions of $14.7 million. Subsequently in April 2021, we redeemed at par all of our Senior Secured Notes ~~bear interest at an annual rate~~(defined below), which was the intended use of ~~3.25% and are due on April 1, 2028. Interest is payable semi-annually in arrears on each April 1 and October 1, commencing on October 1, 2021. CRP can settle~~proceeds from the Convertible Senior Notes ~~by paying or delivering cash, shares of the Company’s Class A common stock (the “Common Stock”), or a combination of cash and Common Stock, at CRP’s election.~~offering.

The Convertible Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and

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each of CRP’s current subsidiaries that guarantee CRP’s outstanding Senior Unsecured Notes as defined below.

The Convertible Senior Notes bear interest at an annual rate of 3.25% and are due on April 1, 2028 unless earlier repurchased, redeemed or converted. The Convertible Senior Notes may become convertible prior to April 1, 2028, upon the occurrence of certain events or conditions being met as disclosed in Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report. CRP can settle the Convertible Senior Notes by paying or delivering cash, shares of the Common Stock, or a combination of cash and Common Stock, at CRP’s election.

In connection with the Convertible Senior Notes issuance, CRP entered into privately negotiated capped call spread transactions (the “Capped Call Transactions”), that are expected to reduce potential dilution to our Common Stock upon a conversion and/or offset any cash payments CRP is required to make in excess of the principal amount of the Convertible Senior Notes, subject to a cap. The Capped Call Transactions have an initial strike price of $6.28 per share of Common Stock and an initial capped price of $8.4525 per share of Common Stock (each subject to certain customary adjustments per the agreements).

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, together with the 2026 Senior Notes, the “Senior Unsecured Notes”) in 144A private placements. In May 2020, $110.6 million aggregate principal amount of the 2026 Senior Notes and $143.7 million aggregate principal amount of the 2027 Senior Notes were validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount of 8.00% second lien senior secured notes ~~due~~ (the “Senior Secured Notes”). The Senior Secured Notes were fully redeemed at par in connection with the Convertible Senior Notes issuance during the second quarter of 2021.

The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by Centennial and each of CRP’s current subsidiaries that guarantee CRP’s ~~revolving credit facility.~~Credit Agreement.

The indentures governing the Senior Unsecured 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~~June 30, ~~2021~~2022 and through the filing of this Quarterly Report.

For further information on our Convertible Senior Notes and Senior Unsecured Notes, refer to Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report.

Contractual Obligations

Our contractual obligations include operating and transportation agreements, drilling rig contracts, office and equipment leases, asset retirement obligations, long-term debt obligations and cash interest expense on long-term debt obligations, which we routinely enter into, modify oror extend. Since December 31, ~~2020,~~2021, there have not been any significant, ~~non-routine~~non-routine changes in our contractual obligations other than the ~~changes to certain of our operating lease commitments and principal and interest due under our senior notes~~new frac’ sand agreements entered into as discussed ~~above. Refer to~~in Note ~~13—Leases~~12—Commitments and Contingencies under Part I, Item I of this Quarterly ~~Report for updated contractual obligations associated with our operating leases as of September 30, 2021.~~Report.

Critical Accounting Policies and Estimates

There have been no material changes during the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 to the critical accounting ~~policies previously disclosed in our 2020 Annual Report.~~policies. 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 ~~2020~~2021 Annual Report for a discussion of our critical accounting policies and estimates.

New Accounting Pronouncements

~~Please refer to~~ ~~Note 1—Basis of Presentation and Summary of Significant Accounting Policies~~ ~~under Part I, Item 1. of this Quarterly Report for a discussion of recently adopted~~There were no significant new accounting standards ~~and the~~adopted or new accounting pronouncements that would have potential effects to us as of ~~new accounting pronouncements.~~June 30, 2022.

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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 for the foreseeable future. Based on our production for the first ~~nine months~~half of ~~2021,~~2022, our oil and gas sales for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 would have moved up or down ~~$51.2~~$61.2 million for each 10% change in oil prices per Bbl, ~~$9.5~~$10.1 million for each 10% change in NGL prices per Bbl, and ~~$10.6~~$10.7 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 that can emanate from ~~operations due to~~ fluctuations in oil and natural gas prices, and thereby 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 table below summarizes the terms of the derivative contracts we had in place as of ~~September~~June 30, ~~2021~~2022 and additional contracts entered into through ~~October~~July 31, ~~2021.~~2022. Refer to Note 7—Derivative Instruments in Item 1 of Part I of this Quarterly Report for open derivative positions as of ~~September~~June 30, ~~2021.~~2022.
Period Volume (Bbls) Volume
(Bbls/d)
Wtd. Avg. Crude Price
($/Bbl)(1)
Crude oil swaps
NYMEX WTI October 2021 - December 2021 828,000 9,000 $49.82
January 2022 - March 2022 1,080,000 12,000 65.03
April 2022 - June 2022 1,092,000 12,000 65.28
July 2022 - September 2022 736,000 8,000 64.53
October 2022 - December 2022 644,000 7,000 64.58
January 2023 - March 2023 45,000 500 69.41
April 2023 - June 2023 45,500 500 68.08
ICE Brent October 2021 - December 2021 322,000 3,500 $58.10
Period Volume (Bbls) Volume
(Bbls/d)
Wtd. Avg. Collar Price Ranges
($/Bbl)(2)
Crude oil collars
NYMEX WTI October 2021 - December 2021 92,000 1,000 $42.00 - $50.10
January 2022 - March 2022 225,000 2,500 63.60 - 74.30
April 2022 - June 2022 227,500 2,500 63.20 - 72.41
ICE Brent October 2021 - December 2021 138,000 1,500 $66.67 - $74.80


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Crude Price ($/Bbl)(1)
Crude oil swaps	July 2022 - September 2022	782,000	8,500	$65.46
	October 2022 - December 2022	690,000	7,500	65.63
	January 2023 - March 2023	225,000	2,500	73.51
	April 2023 - June 2023	227,500	2,500	73.25
	July 2023 - September 2023	92,000	1,000	72.98
	October 2023 - December 2023	92,000	1,000	72.98


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Collar Price Ranges ($/Bbl)(2)
Crude oil collars	July 2022 - September 2022	460,000	5,000	$78.00	-	$107.13
	October 2022 - December 2022	644,000	7,000	80.00	-	104.17
	January 2023 - March 2023	810,000	9,000	75.56	-	91.15
	April 2023 - June 2023	819,000	9,000	75.56	-	91.15
	July 2023 - September 2023	644,000	7,000	76.43	-	92.70
	October 2023 - December 2023	644,000	7,000	76.43	-	92.70

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Period Volume (Bbls) Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(3)
Crude oil differential basis swaps October 2021 - December 2021 644,000 7,000 $0.26
January 2022 - March 2022 450,000 5,000 0.22
April 2022 - June 2022 455,000 5,000 0.22
July 2022 - September 2022 460,000 5,000 0.22
October 2022 - December 2022 460,000 5,000 0.22


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Differential ($/Bbl)(3)
Crude oil basis differential swaps	July 2022 - September 2022	552,000	6,000	$0.29
	October 2022 - December 2022	552,000	6,000	0.29

Period Volume (Bbls) Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(4)
Crude oil roll differential swaps January 2022 - March 2022 900,000 10,000 $0.71
April 2022 - June 2022 910,000 10,000 0.71
July 2022 - September 2022 920,000 10,000 0.71
October 2022 - December 2022 920,000 10,000 0.71


	Period	Volume (Bbls)	Volume (Bbls/d)	Wtd. Avg. Differential ($/Bbl)(4)
Crude oil roll differential swaps	July 2022 - September 2022	920,000	10,000	$0.71
	October 2022 - December 2022	920,000	10,000	0.71

(2) These crude oil collars are settled based on the NYMEX WTI ~~or ICE Brent~~ index price, ~~as applicable,~~ on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.

(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.

Period Volume (MMBtu) Volume (MMBtu/d)
Wtd. Avg. Gas Price
($/MMBtu)(1)
Natural gas swaps October 2021 - December 2021 3,680,000 40,000 $2.95
January 2022 - March 2022 2,700,000 30,000 3.00
April 2022 - June 2022 2,730,000 30,000 3.24
July 2022 - September 2022 2,760,000 30,000 3.24
October 2022 - December 2022 1,540,000 16,739 3.15


	Period	Volume (MMBtu)	Volume (MMBtu/d)	Wtd. Avg. Gas Price ($/MMBtu)(1)
Natural gas swaps	July 2022 - September 2022	2,760,000	30,000	$3.24
	October 2022 - December 2022	1,540,000	16,739	3.15

Period Volume (MMBtu) Volume (MMBtu/d)
Wtd. Avg. Differential
($/MMBtu)(2)
Natural gas basis differential swaps October 2021 - December 2021 4,290,000 46,630 $(0.24)
January 2022 - March 2022 2,700,000 30,000 (0.18)


	Period	Volume (MMBtu)	Volume (MMBtu/d)	Wtd. Avg. Differential ($/MMBtu)(2)
Natural gas basis differential swaps	July 2022 - September 2022	1,840,000	20,000	$(0.45)
	October 2022 - December 2022	1,840,000	20,000	(0.45)
	January 2023 - March 2023	2,250,000	25,000	(1.11)
	April 2023 - June 2023	2,275,000	25,000	(1.11)
	July 2023 - September 2023	2,300,000	25,000	(1.11)
	October 2023 - December 2023	2,300,000	25,000	(1.11)

Period Volume (MMBtu) Volume (MMBtu/d)
Wtd. Avg. Collar Price Ranges
($/MMBtu)(3)
Natural gas collars October 2021 - December 2021 1,220,000 13,261 $3.15 - $4.65
January 2022 - March 2022 1,800,000 20,000 3.15 - 4.65
April 2022 - June 2022 910,000 10,000 3.00 - 3.68
July 2022 - September 2022 920,000 10,000 3.00 - 3.68
October 2022 - December 2022 310,000 3,370 3.00 - 3.68


	Period	Volume (MMBtu)	Volume (MMBtu/d)	Wtd. Avg. Collar Price Ranges ($/MMBtu)(3)
Natural gas collars	July 2022 - September 2022	1,840,000	20,000	$3.50	-	$3.97
	October 2022 - December 2022	2,450,000	26,630	3.87	-	5.06
	January 2023 - March 2023	4,950,000	55,000	4.09	-	7.47
	April 2023 - June 2023	4,095,000	45,000	3.72	-	7.32
	July 2023 - September 2023	4,140,000	45,000	3.72	-	7.32
	October 2023 - December 2023	4,140,000	45,000	3.76	-	7.69
	January 2024 - March 2024	1,820,000	20,000	3.25	-	5.31

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Changes in the fair value of derivative contracts from December 31, ~~2020~~2021 to ~~September~~June 30, ~~2021,~~2022, are presented below:


(in thousands)	Commodity derivative asset (liability)
Net fair value of oil and gas derivative contracts outstanding as of December 31, ~~2020~~2021	$	~~(18,209)~~(34,910)
Commodity hedge contract settlement payments, net of any receipts	~~89,195~~116,526
Cash and non-cash mark-to-market losses on commodity hedge contracts(1)	~~(150,686)~~(163,656)
Net fair value of oil and gas derivative contracts outstanding as of ~~September~~June 30, ~~2021~~2022	$	~~(79,700)~~(82,040)


c

(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~~June 30, ~~2021~~2022 would cause a ~~$37.5~~$48.1 million increase or ~~$37.1~~$47.1 million decrease, respectively, in this fair value position, and a hypothetical upward or downward shift of 10% per Mcf in the NYMEX forward curve for natural gas as of ~~September~~June 30, ~~2021~~2022 would cause a ~~$7.8~~$7.2 million increase or ~~$7.7 million~~ decrease ~~respectively,~~ in this same fair value position.

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. CRP’s ~~credit facility~~Credit Agreement interest rate is based on a ~~LIBOR~~SOFR spread, ~~(subject to a 1% floor),~~ which exposes us to interest rate risk ~~on our borrowings outstanding~~ to the extent ~~LIBOR increases above the floor and~~ we have borrowings ~~outstanding. Further, LIBOR rates are expected to no longer be published beginning~~outstanding under this credit facility. As of June 30, ~~2023, however, due to the structure of~~2022, we had no borrowings outstanding under the Credit ~~Agreement, we do not expect the termination of LIBOR rates to have a material impact to us.~~

As of September 30, 2021, we had $205.0 million of debt outstanding under our Credit Agreement, with a weighted average interest rate of 3.25%. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the weighted average interest rate would be approximately $2.1 million per year.Agreement. We do not currently have or intend to enter into any derivative hedge contracts to protect against fluctuations in interest rates applicable to our outstanding indebtedness.

The ~~remaining~~ long-term debt balance of ~~$799.9~~$801.8 million consists of our senior notes, which have fixed interest rates; therefore, this balance is not affected by interest rate movements. For additional information regarding our debt instruments, see Note 4—Long-Term Debt, in Item 1 of Part I of this Quarterly Report.

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Item 4. Controls and Procedures

Evaluation of Disclosure Control and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Exchange Act, we have evaluated, under the supervision and with the participation of 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~~June 30, ~~2021.~~2022. 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~~June 30, ~~2021~~2022 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~~June 30, ~~2021~~2022 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

Refer to in Item 1, Note ~~11—~~12—Commitments and Contingencies under Part I, Item 1. of this Quarterly Report for more information regarding our legal proceedings.

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 ~~2020~~2021 Annual Report and the risk factors and other cautionary statements contained in our other SEC ~~filings.~~filings as well as additional risk factors set forth below. 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~~Other than with respect to the additional risk factors below, there have been no material changes in our risk factors from those described in our ~~2020~~2021 Annual Report or our SEC filings.

Risks Relating to the Transactions

The Transactions are subject to closing conditions and may not be completed, the Business Combination Agreement may be terminated in accordance with its terms, and we may be required to pay a termination fee upon termination.

On May 19, 2022, we entered into a Business Combination Agreement (the “Business Combination Agreement”) with CRP, Colgate Energy Partners III, LLC (“Colgate”), and, solely for purposes of the specified provisions therein, Colgate Energy Partners III MidCo, LLC (the “Colgate Unitholder”), pursuant to which, CRP will merge with and into Colgate (the “Merger”), with CRP surviving the Merger (the “Surviving Company”) and continuing as a subsidiary of the Company.

The transactions contemplated by the Business Combination Agreement (the “Transactions”) are subject to customary closing conditions that must be satisfied or waived prior to the completion of the Transactions, including the expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the rules promulgated thereunder (the “HSR Act”), no agreement shall be in effect between Colgate, Centennial or any of their respective subsidiaries, on the one hand, and the Antitrust Division of the Department of Justice (the “Antitrust Division”) or the U.S. Federal Trade Commission (the “FTC”), on the other hand, not to consummate the Transactions, and approval by our shareholders of the issuance of shares of Centennial common stock to the Colgate Unitholder (the “Stock Issuance Proposal”) and the approval and adoption of a Fourth Amended and Restated Certificate of Incorporation of Centennial Resource Development, Inc. (the “A&R Charter Proposal”). Many of the closing conditions are not within our control. While the waiting period under the HSR Act expired without objections or comments on July 5, 2022, no assurance can be given that no agreement will be in effect between Colgate, Centennial or any of their respective subsidiaries, on the one hand, and the Antitrust Division or FTC, on the other hand, not to consummate the Transactions and clearances and shareholder approvals will be obtained or that the required conditions to closing will be satisfied in a timely manner or at all. Any delay in completing the Transactions could cause the combined company not to realize, or to be delayed in realizing, some or all of the benefits that we expect to achieve if the Transactions are successfully completed within its expected time frame.

Additionally, either party may terminate the Business Combination Agreement under certain circumstances, including, among other reasons, if the Transactions are not completed by February 19, 2023 (subject to an automatic extension of such date

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to May 19, 2023 in certain circumstances if additional time is needed to satisfy regulatory conditions). In addition, if the Business Combination Agreement is terminated under specified circumstances, we may be obligated to pay a termination fee of $72.0 million or to reimburse Colgate for certain of its transaction expenses in an amount of up to $20.0 million.

Moreover, if the Transactions are not completed for any reason, an agreement is in effect between Colgate, Centennial or any of their respective subsidiaries, on the one hand, and the Antitrust Division or FTC, on the other hand, not to consummate the Transactions or shareholder approval of the Stock Issuance Proposal and the A&R Charter Proposal are not obtained, our ongoing businesses may be adversely affected and, without realizing any of the expected benefits of having completed the Transactions, we would be subject to a number of risks, including the following:

•we may experience negative reactions from the financial markets, including negative impacts on our stock price;

•we may experience negative reactions from our customers, suppliers, distributors and employees;

•we will be required to pay our costs relating to the Transactions, such as financial advisory, legal, financing and accounting costs and associated fees and expenses, whether or not the Transactions are completed;

•the market price of our Class A common stock (“Common Stock”) could decline to the extent that the current market price reflects a market assumption that the Transactions will not be completed;

•the Business Combination Agreement places certain restrictions on the conduct of our business prior to completion of the Transactions and such restrictions, the waiver of which are subject to the consent of Colgate, may prevent us from taking actions during the pendency of the Transactions that would be beneficial; and

•matters relating to the Transactions (including integration planning) will require substantial commitments of time and resources by management, which could otherwise have been devoted to day-to-day operations or to other opportunities that may have been beneficial to us as an independent company.

The consideration payable under the Business Combination Agreement is fixed and will not be adjusted based on our performance.

Under the Business Combination Agreement, the total consideration payable by us consists of (i) 269,300,000 shares of Class C Common Stock, (ii) 269,300,000 additional units in the Surviving Company, (iii) $525 million in cash, subject to adjustments for certain Colgate title and environmental defect considerations set forth in the Business Combination Agreement. The purchase price will not be adjusted for changes in the market price of our Common Stock or the economic performance of Centennial or Colgate. If the market price of our Common Stock increases or the economic performance of Colgate relative to us declines (or the economic performance of Colgate relative to us improves), the consideration will not be adjusted to account for any such changes or any effective increase or decrease in the value of the consideration issued or paid to the Colgate Unitholder under the Business Combination Agreement.

We will be subject to business uncertainties and contractual restrictions, including the risk of litigation, while the Transactions are pending that may cause disruption and may make it more difficult to maintain relationships with employees, suppliers or customers.

Uncertainty about the effect of the Transactions on employees, suppliers and customers may have an adverse effect on Centennial and/or Colgate, which uncertainties may impair our or Colgate’s ability to attract, retain and motivate key personnel until the Transactions are completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with Centennial or Colgate to seek to change existing business relationships with either of us.

Employee retention and recruitment may be challenging before the completion of the Transactions, as employees and prospective employees may experience uncertainty about their future roles following the Transactions. Key employees may depart or prospective key employees may fail to accept employment with us or Colgate because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company following the Transactions, any of which could have a material adverse effect on our business, financial condition and results of operations.

The pursuit of the Transactions and the preparation for the integration may place a significant burden on management and internal resources. The diversion of management’s attention away from day-to-day business concerns and any difficulties encountered in the transition and integration process could have a material adverse effect on our business, financial condition and results of operations.

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Until the completion of the Transactions or the termination of the Business Combination Agreement in accordance with its terms, we are prohibited from entering into certain transactions and taking certain actions that might otherwise be beneficial to us and our shareholders.

During the period between the date of the Business Combination Agreement and completion of the Transactions which, under the Business Combination Agreement, could take until February 19, 2023 (or until May 19, 2023 upon the automatic extension of such date in certain circumstances if additional time is needed to satisfy regulatory conditions), the Business Combination Agreement restricts us from taking specified actions or from pursuing what might otherwise be attractive business opportunities or making other changes to our business, in each case without the consent of Colgate. These restrictions may prevent us from taking actions during the pendency of the Transactions that would have been beneficial. Adverse effects arising from these restrictions during the pendency of the Transactions could be exacerbated by any delays in consummation of the Transactions or termination of the Business Combination Agreement.

The Business Combination Agreement limits our ability to pursue alternatives to the Transactions and may discourage a potential competing acquirer of Centennial, including the payment by Centennial of a termination fee.

The Business Combination Agreement contains provisions that, subject to limited exceptions, restrict our ability to (i) directly or indirectly initiate or solicit, or encourage or facilitate any inquiry or the making or submission of any proposal that constitutes, or would reasonably be expected to lead to, a Parent Acquisition Proposal (as defined in the Business Combination Agreement), (ii) other than clarifying terms of the Parent Acquisition Proposal so that Parent may inform itself about such Parent Acquisition Proposal or to inform a third party or its representatives of the restrictions imposed in accordance with the applicable terms of the Business Combination Agreement, participate or engage in discussions or negotiations with, or disclose any information or data related to Centennial or its subsidiaries or afford access to the properties, books or records of Centennial or its subsidiaries to any person that has made a Parent Acquisition Proposal or to any person in contemplation of making a Parent Acquisition Proposal, or (iii) accept a Parent Acquisition Proposal or enter into any agreement, including any letter of intent, memorandum of understanding, agreement in principal, merger agreement, acquisition agreement, option agreement, joint venture agreement, partnership agreement or other similar agreement, arrangement or understanding, (A) constituting or related to, or that is intended to or would reasonably be expected to lead to, any Parent Acquisition Proposal (other than a confidentiality agreement as provided in the Business Combination Agreement) or (B) requiring, intending to cause, or which could reasonably be expected to cause Centennial to abandon, terminate or fail to consummate the Transactions. In addition, before the Board withdraws, qualifies or modifies its recommendation of the proposed Transactions or terminates the Business Combination Agreement to enter into a definitive agreement with respect to a competing transaction, Colgate generally has an opportunity to offer to modify the terms of the proposed Transactions or Business Combination Agreement. In some circumstances, upon termination of the Business Combination Agreement, we will be required to pay Colgate a termination fee equal to $72.0 million.

These provisions could discourage a potential third-party acquirer that might have an interest in acquiring all or a significant portion of us from considering or proposing that acquisition, even if it were prepared to pay above market value, or might otherwise result in a potential third-party acquirer proposing to pay a lower price to Centennial shareholders than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances.

If the Business Combination Agreement is terminated and we decide to seek another merger transaction, we may not be able to negotiate or consummate a transaction with another party on terms comparable to, or better than, the terms of the Business Combination Agreement.

The Transactions will involve substantial costs.

We have incurred and expect to incur non-recurring costs associated with the Transactions and combining the operations of the two companies, as well as transaction fees and other costs related to the Transactions. These costs and expenses include fees paid to legal, financial and accounting advisors, regulatory and public relations advisors, filing fees, printing costs and other costs and expenses. A significant portion of these transaction costs is contingent upon the Closing occurring, although some have been and will be incurred regardless of whether the Transactions are consummated.

In addition, the combined company will also incur significant restructuring and integration costs in connection with the integration of Centennial and Colgate and the execution of our business plan, including costs relating to formulating and implementing integration plans and eliminating duplicative costs, as well as potential employment-related costs. The costs related to restructuring will be expensed as a cost of the ongoing results of operations of either us or the combined company. There are processes, policies, procedures, operations, technologies and systems that must be integrated in connection with the Transactions and the integration of Colgate’s business. While we have assumed a certain level of expenses would be incurred to integrate Centennial and Colgate and achieve synergies and efficiencies and we continue to assess the magnitude of these costs, many of these expenses are, by their nature, difficult to estimate accurately and there are many factors beyond our control that could affect the total amount or timing of these costs. Although we expect that the elimination of duplicative costs, as well as the realization of

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strategic benefits, additional income, synergies and other efficiencies should allow the combined company to offset integration-related costs over time, this net benefit may not be achieved in the near term, or at all.

Securities class action and derivative lawsuits may be filed against us, or against our directors, challenging the Transactions, and an adverse ruling in any such lawsuit may prevent the Transactions from becoming effective or from becoming effective within the expected time frame.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Transactions like the Transactions are frequently subject to litigation or other legal proceedings, including actions alleging that our Board breached their fiduciary duties to our shareholders by entering into the Business Combination Agreement. We cannot provide assurance that such litigation or other legal proceedings will not be brought. If litigation or other legal proceedings are in fact brought against us, or against our Board, we will defend against it, but might not be successful in doing so. An adverse outcome in such matters, as well as the costs and efforts of a defense even if successful, could have a material adverse effect on the business, results of operation or financial position of us or the combined company, including through the possible diversion of company resources or distraction of key personnel.

Lawsuits that may be brought against us, Colgate or our or its directors could also seek, among other things, injunctive relief or other equitable relief, including a request to enjoin us from consummating the Transactions. One of the conditions to the Closing are that no order, award or judgment by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case, that prohibits or makes illegal the Closing. Consequently, if a plaintiff is successful in obtaining an order, award or judgment prohibiting completion of the Transactions, that order, award or judgment may delay or prevent the Transactions from being completed within the expected time frame or at all, which may adversely affect our business, financial position and results of operations.

We will incur additional indebtedness in connection with the Transactions, and the combined company’s debt may impose certain financial and operational limitations.

In addition to our existing indebtedness under our credit facilities and indentures, we plan to (i) incur additional debt under CRP’s revolving credit facility in order to fund the approximately $525 million of Cash Consideration and (ii) assume $1.0 billion of Colgate’s senior notes and Colgate’s credit facility borrowings outstanding at closing as part of the Transactions. The amount of debt to be borrowed under CRP’s revolving credit facility as part of the Transactions will be dependent upon the amount of our cash and cash equivalents as of the closing date of the Merger.

While we expect to generate material free cash flow prior to the Closing to offset a portion of this debt, the combined company’s level of indebtedness following completion of the Transactions could have important consequences. For example, it could:

•increase our vulnerability to general adverse economic and industry conditions;

•impair our ability to obtain additional debt or equity financing in the future for working capital, capital expenditures development of estimated proved undeveloped reserves (‘PUDs”), development and acquisition projects, acquisitions or general corporate or other purposes;

•require us to dedicate a material portion of our cash flows to the payment of principal and interest on our indebtedness, thereby reducing the availability of our cash flows to fund working capital needs, capital expenditures, development of estimated PUDs, development and acquisition projects, acquisitions and other general corporate purposes;

•expose us to variable interest rate risk to the extent we make borrowings under CRP’s revolving credit facility;

•limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•place us at a disadvantage compared to our competitors that have less indebtedness; and

•limit our ability to adjust to changing market conditions.

Any of these risks could materially impact our ability to fund our operations or limit our ability to expand the combined business, which could have a material adverse effect on the combined business, financial condition and results of operations.

Combining the businesses of Centennial and Colgate may be more difficult, costly or time-consuming than expected and the combined company may fail to realize the anticipated synergies and other benefits of the Transactions, which may adversely affect the combined company’s business results and negatively affect the value of our Common Stock following the consummation of the Transactions.

Centennial and Colgate have operated and, until the completion of the Transactions will continue to operate, independently. The success of the Transactions will depend on, among other things, the ability of Centennial and Colgate to combine their businesses in a manner that facilitates growth opportunities and realizes expected cost savings. We have entered into the Business

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Combination Agreement because we believe that the transactions contemplated by the Business Combination Agreement are fair to and in the best interests of our shareholders and that combining the businesses of Centennial and Colgate will produce benefits as well as cost savings and other cost and capital expenditure synergies.

Following the Closing, Centennial and Colgate must successfully combine their respective businesses in a manner that permits these benefits to be realized. For example, the following issues, among others, must be addressed in integrating the operations of the two companies in order to realize the anticipated benefits of the Transactions:

•combining the companies’ operations and corporate functions;

•combining the businesses of Centennial and Colgate and meeting the capital requirements of the combined company, in a manner that permits the combined company to achieve any cost savings or other synergies anticipated to result from the Transactions, the failure of which would result in the anticipated benefits of the Transactions not being realized in the time frame currently anticipated or at all;

•integrating personnel from the two companies;

•integrating and unifying our reserves and the development of our new PUDs;

•identifying and eliminating underperforming or uncertain wells;

•harmonizing the companies’ operating practices, employee development and compensation programs, internal controls and other policies, procedures and processes;

•maintaining existing agreements with customers, suppliers, distributors and vendors, avoiding delays in entering into new agreements with prospective customers, suppliers, distributors and vendors, and leveraging relationships with such third parties for the benefit of the combined company;

•addressing possible differences in business backgrounds, corporate cultures and management philosophies;

•consolidating the companies’ administrative and information technology infrastructure;

•coordinating distribution and marketing efforts;

•managing the movement of certain positions to the new proposed headquarters in Midland, Texas; and

•effecting actions that may be required in connection with obtaining regulatory or other governmental approvals.

It is possible that the integration process could result in the loss of key Centennial or Colgate employees, the loss of customers, the disruption of either company’s or both companies’ ongoing businesses, inconsistencies in standards, controls, procedures and policies, unexpected integration issues, higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. In addition, the actual integration may result in additional and unforeseen expenses. If the combined company is not able to adequately address integration challenges, we may be unable to successfully integrate operations and the anticipated benefits of the integration plan may not be realized.

In addition, the combined company must achieve the anticipated growth and cost savings without adversely affecting current revenues and investments in future growth. If the combined company is not able to successfully achieve these objectives, the anticipated synergies and other benefits of the Transactions may not be realized fully, or at all, or may take longer to realize than expected. Additionally, we may inherit from Colgate legal, regulatory, and other risks that occurred prior to the Transactions, whether known or unknown to us, which may be material to the combined company. Actual growth, cost and capital expenditure synergies and other cost savings, if achieved, may be lower than what we expect and may take longer to achieve than anticipated. Moreover, at times the attention of the combined company’s management and resources may be focused on the integration of the businesses of the two companies and diverted from day-to-day business operations or other opportunities that may have been beneficial to such company, which may disrupt the combined company’s ongoing business.

An inability to realize the full extent of the anticipated benefits of the Transactions, as well as any delays encountered in the integration process, could have an adverse effect upon the revenues, level of expenses and operating results of the combined company, which may adversely affect the value of our Common Stock following the consummation of the Transactions. Moreover, if the combined company is unable to realize the full strategic and financial benefits currently anticipated from the Transactions, Centennial shareholders will have experienced substantial dilution of their ownership interests without receiving any commensurate benefit, or only receiving part of the commensurate benefit to the extent the combined company is able to realize only part of the strategic and financial benefits currently anticipated from the Transactions.

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The combined company may not be able to retain customers, suppliers or distributors, or customers, suppliers or distributors may seek to modify contractual relationships with the combined company, which could have an adverse effect on the combined company’s business and operations. Third parties may terminate or alter existing contracts or relationships with the combined company.

As a result of the Transactions, the combined company may experience impacts on relationships with customers, suppliers and distributors that may harm the combined company’s business and results of operations. Certain customers, suppliers or distributors may seek to terminate or modify contractual obligations following the Transactions whether or not contractual rights are triggered as a result of the Transactions. There can be no guarantee that customers, suppliers and distributors will remain with or continue to have a relationship with the combined company or do so on the same or similar contractual terms following the Transactions. If any customers, suppliers or distributors seek to terminate or modify contractual obligations or discontinue the relationship with the combined company, then the combined company’s business and results of operations may be harmed. If the combined company’s suppliers were to seek to terminate or modify an arrangement with the combined company, then the combined company may be unable to procure necessary supplies from other suppliers in a timely and efficient manner and on acceptable terms, or at all.

We and Colgate also have contracts with third parties which may require consent from these parties in connection with the Transactions, or which may otherwise contain limitations applicable to such contracts following the Transactions. If these consents cannot be obtained, the combined company may suffer a loss of potential future revenue, incur costs and lose rights that may be material to the combined company’s business. In addition, third parties with whom we or Colgate currently have relationships may terminate or otherwise reduce the scope of their relationship in anticipation of the Transactions. Any such disruptions could limit the combined company’s ability to achieve the anticipated benefits of the Transactions. The adverse effect of any such disruptions could also be exacerbated by a delay in the completion of the Transactions or by a termination of the Business Combination Agreement.

Colgate is currently not a U.S. public reporting company and the obligations associated with integrating into a public company may require significant resources and management attention.

Colgate is, and prior to the consummation of the Transactions will remain, a private company that is not subject to reporting requirements and does not have accounting personnel specifically employed to review internal controls over financial reporting. Upon completion of the Transactions, the Colgate business will become subject to the rules and regulations established from time to time by the SEC and Nasdaq. In addition, as a public company, we are required to document and test our internal controls over financial reporting pursuant to

Section 404(b) of the Sarbanes-Oxley Act of 2002, so that our management can certify as to the effectiveness of our internal control over financial reporting in connection with the annual report. Colgate is required to be included in the scope of our internal control over financial reporting in the annual report to be filed with the SEC for the fiscal year following the fiscal year in which the Transactions are consummated and thereafter, which requires us to make and document significant changes to our internal controls over financial reporting. Bringing Colgate into compliance with these rules and regulations and integrating Colgate into our current compliance and accounting system may increase our legal and financial compliance costs, make some activities more difficult, time-consuming or costly and increase demand on our systems and resources. Furthermore, the need to establish the necessary corporate infrastructure to integrate Colgate may divert management’s attention from implementing our growth strategy, which could prevent us from improving our business, financial condition and results of operations. However, the measures we take may not be sufficient to satisfy our obligations as a public company. If we do not continue to develop and implement the right processes and tools to manage our changing enterprise upon the Transactions and maintain our culture, our ability to compete successfully and achieve our business objectives could be impaired, which could negatively impact our business, financial condition and results of operations. In addition, we cannot predict or estimate the amount of additional costs we may incur to bring Colgate into compliance with these requirements. We anticipate that these costs will materially increase our selling, general and administration expenses. In addition, bringing Colgate into compliance with these rules and regulations will increase our legal and financial compliance costs and will make some activities more time- consuming and costly. These additional obligations could have a material adverse effect on our business, financial condition, results of operations and cash flow.

The Proposed Charter will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for substantially all actions and proceedings that may be initiated by shareholders, which could limit shareholders’ ability to obtain a favorable judicial forum for disputes with the combined company or its directors, officers, employees or agents.

The Proposed Charter will provide that, unless the combined company consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the combined company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of the directors, officers, employees or agents of the combined company to the combined company or its shareholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware

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General Corporation Law, the Proposed Charter or the combined company’s bylaws or (iv) any action asserting a claim against the combined company that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. In the event the Delaware Court of Chancery lacks subject matter jurisdiction, then the sole and exclusive forum for such action or proceeding shall be the federal district court for the District of Delaware. Any person or entity purchasing or otherwise acquiring any interest in shares of the capital stock of the combined company will be deemed to have notice of, and consented to, the provisions of the Proposed Charter described in the preceding sentences.

This provision would not apply to claims brought to enforce a duty or liability created by the Exchange Act, the Securities Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. This choice of forum provision may limit a shareholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with the combined company or the directors, officers, employees or agents of the combined company, which may discourage such lawsuits against the combined company and such persons. Alternatively, if a court were to find these provisions of the Proposed Charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, the combined company may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect the business, financial condition or results of operations of the combined company.

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Item 6. Exhibits


Exhibit Number						Description of Exhibit
2.1						Business Combination Agreement, dated as of May 19, 2022, by and among Centennial Resource Development, Inc., Centennial Resource Production, LLC, Colgate Energy Partners III, LLC, and, solely for purposes of the specified provisions therein, Colgate Energy Partners Holdings III, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 19, 2022).
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 as 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 as 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 as 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 as 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 as 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 as filed with the SEC on August 6, 2018).
~~10.1#~~10.1						~~Form of Performance Restricted Stock Unit~~Limited Consent and Waiver and First Amendment to Third Amended and Restated Credit Agreement ~~under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan~~ (incorporated by reference to Exhibit 10.1 to the ~~Company's Quarterly~~Company’s Current Report on Form ~~10-Q as~~8-K filed with the SEC on ~~August 4, 2021)~~July 21 , 2022).
10.2						Voting and Support Agreement, dated as of May 19, 2022, by and among Centennial Resource Development, Inc., Riverstone VI Centennial QB Holdings, L.P., REL US Centennial Holdings, LLC, Riverstone Non-ECI USRPI AIV, L.P., Silver Run Sponsor, LLC and Colgate Energy Partners III, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 19, 2022)
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.

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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 Executive Vice President and Chief Financial Officer

			Date:			~~November~~August 4, ~~2021~~2022

5456


(in thousands)	Total(2)
2021(1)	$	468
2022	1,898
2023	2,985
2024	2,670
2025	2,086
2026 and thereafter	12,669
Total lease payments	22,776
Less: imputed interest	(4,565)
Present value of lease liabilities (3)	$	18,211