CDEV Centennial Resource Development Inc

Centennial Resource Development, Inc. (“Centennial” or the “Company”) (NASDAQ: CDEV) today announced the establishment of a share repurchase program, its 2021 financial and operational results, and 2022 operational plans.

Shareholder Return Program

• Announced $350 million stock repurchase program
• Supported by robust two-year outlook and resilient through commodity price cycles

Recent Financial and Operational Highlights

• Generated record free cash flow1 of $85 million in the fourth quarter, and over $200 million for the full year
• Closed the previously announced non-core asset divestiture in Reeves County for $101 million
• Repaid $180 million in borrowings during the fourth quarter
• Reduced leverage metrics
• Delivered three of the top ten wells in Company history
• Increased daily crude oil production 3% compared to the prior quarter
• Entered into a new $750 million, five-year revolving credit facility

2022 Financial and Operational Plan

• Expect to generate over $400 million in free cash flow assuming current strip pricing
• Plan to maintain two-rig drilling program
• Expect to deliver 10% to 15% crude oil production growth year-over-year, adjusted for recent divestiture
• Anticipate further reduction in leverage and total debt outstanding

Financial Results

For the full year 2021, Centennial generated net cash from operating activities of $525.6 million and free cash flow of $206.7 million. The Company also reported full year net income of $138.2 million, or $0.46 per diluted share, compared to a net loss of $682.8 million, or $(2.46) loss per diluted share, in the prior year. For the fourth quarter, net income was $160.8 million, or $0.51 per diluted share, compared to a net loss of $88.7 million, or $(0.32) loss per diluted share, in the prior year period. The Company generated net cash from operating activities of $192.5 million and free cash flow of $84.8 million in the fourth quarter of 2021.

Full year total equivalent production averaged 60,939 barrels of oil equivalent per day (“Boe/d”) compared to 67,161 Boe/d in the prior year. Average daily crude oil production during the full year was 32,058 barrels of oil per day (“Bbls/d”) compared to 36,084 Bbls/d in the prior year. For the fourth quarter, total equivalent production was 62,649 Boe/d compared to 59,708 Boe/d in the prior year period, an increase of 5%. Average daily crude oil production for the quarter increased 14% to average 34,468 Bbls/d compared to 30,196 Bbls/d in the prior year period.

“2021 was an excellent year for Centennial. We generated over $200 million in free cash flow, allowing us to significantly pay down debt and reduce leverage during the year,” said Sean R. Smith, Chief Executive Officer. “Using current strip pricing, we expect strong free cash flow and further debt reduction during 2022, while also delivering solid oil production growth. Given our enhanced financial and operational position, we are excited to begin returning capital to our shareholders in the coming quarters.”

Stock Repurchase Program

Centennial announced a $350 million stock repurchase program. The program is authorized for two years and represents approximately 15% of the Company’s current market capitalization. Upon achieving a net debt-to-LTM EBITDAX2 ratio of approximately 1.0x or lower, the Company plans to begin repurchasing shares.

“I am pleased to announce our first step in returning capital to shareholders through a disciplined share buyback program, which we believe will drive value creation in today’s environment,” said Smith. “The program is supported by a robust two-year outlook, during which we expect to generate over $775 million in free cash flow at current strip prices and deliver average crude oil production growth of over 10%.”

Smith continued, “We remain focused on further balance sheet improvement and expect to initiate our share repurchase program after achieving our leverage target, which is anticipated to occur during the second quarter of this year assuming current strip prices. Importantly, the execution of this program is not contingent on current strip pricing and is resilient through commodity price cycles, all while maintaining a leverage ratio of 1.0x or less.”

Repurchases under the program may be made from time to time in the open markets or in privately negotiated transactions at the Company’s discretion and are subject to market conditions, applicable legal requirements, available liquidity, compliance with the Company’s debt and other agreements and other factors. The program does not require any specific number of shares to be reacquired and can be modified or discontinued by the Board of Directors at any time.

Fourth Quarter Operational Results

Centennial has continued to efficiently develop its Delaware Basin acreage position with larger well packages. During the quarter, the Company completed nine wells across two separate developments, which were brought online in late October and early November. Located on the southern portion of its New Mexico position, the Juliet, Sheba and Solomon (average 89% working interest (“WI”)) four-well development was drilled in the Second Bone Spring Sand interval with average 7,150-foot laterals. The wells delivered an average 30-day initial production (“IP”) rate of 3,080 Boe/d (82% oil) per well and averaged 354 Bbls/d of oil per 1,000 foot of lateral per well. Notably, the average maximum IP-24 hour rate for the Juliet 514H, Sheba 506H and Solomon 505H wells was over 4,800 barrels of oil.

“These wells generated outstanding results and now represent three of the top ten wells drilled in the Company’s history, based on 90-day rates,” said Smith. “This development highlights the quality of our asset base and our technical expertise, averaging almost 1,700 barrels of oil per day during the first ninety days.”

Also targeting the Second Bone Spring Sand, the Winnebago and Bridge wells (average 98% WI) represent a five-well development drilled with 9,760-foot average laterals. The wells averaged 1,638 Boe/d, or 1,325 Bbls/d of oil, per well for the 30-day IP period.

Total capital expenditures incurred for the quarter were $86.5 million. Fourth quarter drilling, completion and facilities (“DC&F”) costs were $85.2 million and included facilities capital for wells scheduled to be completed during the first quarter of 2022. Infrastructure, land and other capital expenditures during the quarter totaled $1.3 million. For the full year, total capital expenditures were $321.5 million.

2022 Operational Plans and Targets

In 2022, Centennial plans to continue operating its current two-rig drilling program, which is estimated to generate over $400 million in free cash flow at current strip prices. Given operational efficiencies realized to date, Centennial expects to deliver crude oil production growth of 10% to 15%, after adjusting for approximately 1,000 Bbls/d of oil production for the full year 2021 associated with its recent divestiture. “Our game plan will deliver solid oil growth and material free cash flow, while simultaneously reducing our leverage metrics,” said Smith.

The estimated fiscal year 2022 total capital budget is approximately $365 million to $425 million. Total DC&F costs are estimated to be $350 million to $400 million. Centennial has allocated approximately $15 million to $25 million to infrastructure, land and other capital expenditures which includes approximately $14 million related to environmental stewardship activities, such as water recycling and handling facilities, natural gas infrastructure and emissions monitoring equipment, among other items.

During 2022, Centennial anticipates that approximately 80% of its completions will be in Lea County, New Mexico. The Company will focus the majority of its Lea County activity in the Second and Third Bone Spring Sand intervals, while continuing to develop and test additional zones. The remaining activity will be in Reeves County, Texas. Due to reduced cycle times, the Company expects its gross number of operated spuds and completions to increase 4% and 19%, respectively, compared to the prior year. (For a detailed table summarizing Centennial’s 2022 operational and financial guidance, please see the Appendix of this press release.)

Capital Structure and Liquidity

During the fourth quarter, Centennial repaid $180 million of borrowings under its revolving credit facility, leaving $25 million outstanding at December 31, 2021. Total debt at the end of the quarter was $841 million and represents an 18% reduction from the prior quarter. Net debt-to-LTM EBITDAX at December 31, 2021 was 1.4x compared to 2.1x at September 30, 2021.

On February 18, 2022, the Company closed a new five-year revolving credit facility with elected commitments of $750 million. The borrowing base under the new credit facility increased to $1.15 billion from $700 million under the Company’s prior credit facility. Additionally, the new revolving credit facility provides for, among other things, the ability to repurchase outstanding common stock and senior notes, subject to certain leverage and elected commitment availability conditions. As of December 31, 2021, after giving effect to the new elected commitments, pro forma total liquidity was approximately $729 million, including letters of credit.

“During 2021, we repaid $305 million in borrowings under our credit facility and reduced our net debt-to-LTM EBITDAX metric by almost three turns,” said Smith. “Our strong leverage profile, coupled with no debt maturities until early 2026, provide Centennial with significant financial flexibility going forward.”

Year-End 2021 Proved Reserves

Centennial reported year-end 2021 total proved reserves of 305 MMBoe compared to 299 MMBoe at prior year-end. At year-end 2021, proved reserves consisted of 50% oil, 32% natural gas and 18% natural gas liquids. Proved developed reserves were 163 MMBoe (53% of total proved reserves) at December 31, 2021. For 2021, Centennial’s organic reserve replacement ratio was 149%. The Company’s 2021 proved developed finding and development cost was $7.65 per Boe. Centennial’s drill-bit finding and development cost was $9.36 per Boe for 2021. Centennial had a standardized measure of discounted future net cash flows of $3.4 billion at December 31, 2021. The pre-tax present value at 10% (“Pre-tax PV 10%”, a non-GAAP financial measure reconciled within the Appendix) of Centennial’s total proved reserves was $3.9 billion at year-end.

Netherland Sewell & Associates, Inc., an independent reserve engineering firm, prepared Centennial’s year-end reserves estimates for the year ending December 31, 2021. (For additional information relating to our reserves, in addition to an explanation of how we calculate and use the organic reserve replacement ratio and finding and development costs, please see the Appendix of this press release.)

Hedge Position Update

Since its last update on November 3, 2021, the Company has added incremental oil hedges for the second half of 2022 and full year 2023. For the second half of 2022, the Company entered into 500 Bbls/d of incremental oil swaps at a weighted average fixed price of $80.35 per barrel. Also for this period, the Company added 2,000 Bbls/d of oil collars with a weighted average floor price of $75.00 per barrel and ceiling price of $89.05 per barrel. As a result, Centennial now has a total of 12,232 Bbls/d of oil hedged for the full year 2022, consisting of approximately 82% fixed price swaps with the remainder in costless collars. Notably, the Company’s oil hedges are weighted towards the first half of 2022 with 14,500 Bbls/d of oil hedged during this period. For the second half of 2022, Centennial has 10,000 Bbls/d of oil hedged.

For the full year 2023, Centennial has a total of 3,740 Bbls/d of oil hedged, consisting of approximately 47% fixed price swaps. The Company currently has 1,744 Bbls/d of oil hedged at a weighted average fixed price of $73.26 per barrel. Also for 2023, the Company has 1,996 Bbls/d of oil collars in place with a weighted average floor and ceiling price of $70.00 per barrel and $80.91 per barrel, respectively. In addition to the hedge positions discussed above, Centennial has certain other natural gas hedges, crude oil and natural gas basis swaps and crude oil roll differential swaps in place. (For a summary table of Centennial’s derivative contracts as of February 18, 2022, please see the Appendix to this press release.)

Annual Report on Form 10-K

Centennial’s financial statements and related footnotes will be available in its Annual Report on Form 10-K for the year ended December 31, 2021, which is expected to be filed with the Securities and Exchange Commission (“SEC”) on February 24, 2022.

Conference Call and Webcast

Centennial will host an investor conference call on Thursday, February 24, 2022 at 8:00 a.m. Mountain (10:00 a.m. Eastern) to discuss fourth quarter and full year 2021 operating and financial results. Interested parties may join the webcast by visiting Centennial’s website at www.cdevinc.com and clicking on the webcast link or by dialing (844) 348-0017, or (213) 358-0877 for international calls, (Conference ID: 2597505) at least 15 minutes prior to the start of the call. A replay of the call will be available on Centennial’s website or by phone at (855) 859-2056 (Conference ID: 2597505) for a seven-day period following the call.

About Centennial Resource Development, Inc.

Centennial Resource Development, Inc. 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. The Company’s assets and operations, which are held and conducted through Centennial Resource Production, LLC, are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. For additional information about the Company, please visit www.cdevinc.com.

Cautionary Note Regarding Forward-Looking Statements

The information in this press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this press release, 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 press release, 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.

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 reduced demand caused by the COVID-19 pandemic and the actions taken in response 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 drilling prospects, inventories, projects and programs;
• our financial strategy, liquidity and capital required for our development program;
• our realized oil, natural gas and NGL prices;
• the timing and amount of our future production of oil, natural gas and NGLs;
• our hedging strategy and results;
• our competition and government regulations;
• our ability to obtain permits and governmental approvals;
• our pending legal or environmental matters;
• the marketing and transportation of our oil, natural gas and NGLs;
• our leasehold or business acquisitions;
• costs 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;
• our plans, objectives, expectations and intentions contained in this press release that are not historical; and
• the other factors described in our most recent Annual Report on Form 10-K, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

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 oil and gas 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 our filings with the SEC.

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 oil and gas 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 this press release occur or should 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 press release 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 statements in this section, to reflect events or circumstances after the date of this press release.

1) Free Cash Flow is a non-GAAP financial measure. See “Non-GAAP Financial Measures” included within the Appendix of this press release for related disclosures and a reconciliation to net cash provided by operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP.

2) Net debt-to-LTM EBITDAX, also referred to as “leverage” in this press release, is a non-GAAP financial measure. The Company defines net debt as long-term debt, net, plus unamortized debt discount and debt issuance costs on senior notes minus cash and cash equivalents. The Company defines net debt-to-LTM EBITDAX as net debt (defined above) divided by Adjusted EBITDAX (defined and reconciled in the Appendix of this press release for the three and twelve month periods ended December 31, 2021 and 2020). The Company refers to this metric to show trends that investors may find useful in understanding the Company’s ability to service its debt. This metric is widely used by professional research analysts, including credit analysts, in the valuation and comparison of companies in the oil and gas exploration and production industry. Centennial does not provide guidance on the items used to reconcile between forecasted net debt-to-LTM EBITDAX to forecasted long-term debt, net, or forecasted net income due to the uncertainty regarding timing and estimates of certain items. Therefore, Centennial cannot reconcile forecasted net debt-to-LTM EBITDAX to forecasted long-term debt, net, or forecasted net income without unreasonable effort.

Contact:Hays MabrySr. Director, Investor Relations(832) 240-3265ir@cdevinc.com

Details of our 2022 operational and financial guidance are presented below:

	2022 FY Guidance
Net average daily production (Boe/d)	61,500	—	67,500
Net average daily oil production (Bbls/d)	33,500	—	36,500
Production costs
Lease operating expenses ($/Boe)	$4.65	—	$5.25
Gathering, processing and transportation expenses ($/Boe)	$3.45	—	$3.95
Depreciation, depletion, and amortization ($/Boe)	$12.00	—	$14.00
Cash general and administrative ($/Boe)1	$1.95	—	$2.25
Stock-based compensation ($/Boe)2	$1.50	—	$2.00
Severance and ad valorem taxes (% of revenue)	6.0%	—	8.0%
Capital expenditure program ($MM)	$365	—	$425
Drilling, completion and facilities	$350	—	$400
Infrastructure, land and other	$15	—	$25
Operated drilling program
Wells spud (gross)	47	—	53
Wells completed (gross)	47	—	53
Average working interest	~85%
Average lateral length (feet)	~8,750

(1) Cash general and administrative guidance does not include the portion of stock-based compensation that will settle in cash.

(2) Stock-based compensation guidance includes expense amounts for both equity awards and for cash-based liability awards. The amount of actual expense to be incurred for the cash-based liability awards included in this guidance range may vary from our forecast, as such expense can fluctuate materially in future periods with changes in Centennial’s future stock price and, for certain awards, with changes in Centennial’s future stock price performance versus a defined peer group of companies.

Centennial Resource Development, Inc.Operating Highlights

	Three Months Ended December 31,								Year Ended December 31,
	2021				2020				2021				2020
Net revenues (in thousands):
Oil sales	$	230,791			$	112,123			$	743,069			$	475,694
Natural gas sales		43,212				17,724				149,478				46,776
NGL sales		42,416				18,230				137,345				57,986
Oil and gas sales	$	316,419			$	148,077			$	1,029,892			$	580,456
Average sales price:
Oil (per Bbl)	$	72.78			$	40.36			$	63.50			$	36.02
Effect of derivative settlements on average price (per Bbl)		(10.36	)			(1.54	)			(10.19	)			(3.15	)
Oil net of hedging (per Bbl)	$	62.42			$	38.82			$	53.31			$	32.87
Average NYMEX price for oil (per Bbl)	$	77.09			$	42.66			$	67.89			$	39.44
Oil differential from NYMEX		(4.31	)			(2.30	)			(4.39	)			(3.42	)
Natural gas (per Mcf)	$	4.41			$	1.76			$	3.67			$	1.13
Effect of derivative settlements on average price (per Mcf)		(1.03	)			(0.09	)			(0.32	)			(0.12	)
Natural gas net of hedging (per Mcf)	$	3.38			$	1.67			$	3.35			$	1.01
Average NYMEX price for natural gas (per Mcf)	$	4.74			$	2.47			$	3.84			$	1.99
Natural gas differential from NYMEX		(0.33	)			(0.71	)			(0.17	)			(0.86	)
NGL (per Bbl)	$	44.28			$	17.65			$	36.61			$	12.91
Net production:
Oil (MBbls)		3,170				2,778				11,701				13,207
Natural gas (MMcf)		9,808				10,093				40,741				41,302
NGL (MBbls)		958				1,032				3,752				4,490
Total (MBoe)(1)		5,764				5,493				22,243				24,581
Average daily net production:
Oil (Bbls/d)		34,468				30,196				32,058				36,084
Natural gas (Mcf/d)		106,613				109,712				111,619				112,848
NGL (Bbls/d)		10,412				11,226				10,278				12,269
Total (Boe/d)(1)		62,649				59,708				60,939				67,161

_________________________

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

Centennial Resource Development, Inc.Operating Expenses

	Three Months Ended December 31,								Year Ended December 31,
	2021				2020				2021				2020
Operating costs (in thousands):
Lease operating expenses	$	28,897			$	26,261			$	106,419			$	109,282
Severance and ad valorem taxes		20,973				9,309				67,140				39,417
Gathering, processing, and transportation expense		21,613				17,956				85,896				71,309
Operating cost metrics:
Lease operating expenses (per Boe)	$	5.01			$	4.78			$	4.78			$	4.45
Severance and ad valorem taxes (% of revenue)		6.6	%			6.3	%			6.5	%			6.8	%
Gathering, processing, and transportation expense (per Boe)		3.75				3.27				3.86				2.90

Centennial Resource Development, Inc.Consolidated Statements of Operations(in thousands, except per share data)

	Three Months Ended December 31,								Year Ended December 31,
	2021				2020				2021				2020
Operating revenues
Oil and gas sales	$	316,419			$	148,077			$	1,029,892			$	580,456
Operating expenses
Lease operating expenses		28,897				26,261				106,419				109,282
Severance and ad valorem taxes		20,973				9,309				67,140				39,417
Gathering, processing and transportation expenses		21,613				17,956				85,896				71,309
Depreciation, depletion and amortization		75,863				74,832				289,122				358,554
Impairment and abandonment expense		6,400				40,561				32,511				691,190
Exploration and other expenses		3,185				7,625				7,883				18,355
General and administrative expenses		20,643				18,421				110,454				72,867
Total operating expenses		177,574				194,965				699,425				1,360,974
Net gain (loss) on sale of long-lived assets		34,422				10				34,168				398
Proceeds from terminated sale of assets		—				—				5,983				—
Income (loss) from operations		173,267				(46,878	)			370,618				(780,120	)
Other income (expense)
Interest expense		(13,931	)			(17,682	)			(61,288	)			(69,192	)
Gain (loss) on extinguishment of debt		—				—				(22,156	)			143,443
Net gain (loss) on derivative instruments		1,860				(24,205	)			(148,825	)			(64,535	)
Other income (expense)		124				110				395				81
Total other income (expense)		(11,947	)			(41,777	)			(231,874	)			9,797
Income (loss) before income taxes		161,320				(88,655	)			138,744				(770,323	)
Income tax (expense) benefit		(569	)			—				(569	)			85,124
Net income (loss)		160,751				(88,655	)			138,175				(685,199	)
Less: Net (income) loss attributable to noncontrolling interest		—				—				—				2,362
Net income (loss) attributable to Class A Common Stock	$	160,751			$	(88,655	)		$	138,175			$	(682,837	)
Income (loss) per share of Class A Common Stock:
Basic	$	0.57			$	(0.32	)		$	0.49			$	(2.46	)
Diluted	$	0.51			$	(0.32	)		$	0.46			$	(2.46	)

Centennial Resource Development, Inc.Consolidated Balance Sheets(in thousands, except share and per share amounts)

	December 31, 2021				December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	9,380			$	5,800
Accounts receivable, net		71,295				54,557
Prepaid and other current assets		5,860				5,229
Total current assets		86,535				65,586
Property and Equipment
Oil and natural gas properties, successful efforts method
Unproved properties		1,040,386				1,209,205
Proved properties		4,623,726				4,395,473
Accumulated depreciation, depletion and amortization		(1,989,489	)			(1,877,832	)
Total oil and natural gas properties, net		3,674,623				3,726,846
Other property and equipment, net		11,197				12,650
Total property and equipment, net		3,685,820				3,739,496
Noncurrent assets
Operating lease right-of-use assets		16,385				3,176
Other noncurrent assets		15,854				19,167
TOTAL ASSETS	$	3,804,594			$	3,827,425
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	130,256			$	110,439
Operating lease liabilities		1,413				3,155
Other current liabilities		36,230				18,274
Total current liabilities		167,899				131,868
Noncurrent liabilities
Long-term debt, net		825,565				1,068,624
Asset retirement obligations		17,240				17,009
Deferred income taxes		2,589				2,589
Operating lease liabilities		16,002				422
Other noncurrent liabilities		24,579				2,952
Total liabilities		1,053,874				1,223,464
Shareholders’ equity
Common stock, $0.0001 par value, 620,000,000 shares authorized:
Class A: 294,260,623 shares issued and 284,696,972 shares outstanding at December 31, 2021 and 290,645,623 shares issued and 278,551,901 shares outstanding at December 31, 2020		29				29
Additional paid-in capital		3,013,017				3,004,433
Retained earnings (accumulated deficit)		(262,326	)			(400,501	)
Total shareholders’ equity		2,750,720				2,603,961
Noncontrolling interest		—				—
Total equity		2,750,720				2,603,961
TOTAL LIABILITIES AND EQUITY	$	3,804,594			$	3,827,425

Centennial Resource Development, Inc.Consolidated Statements of Cash Flows(in thousands)

	Year Ended December 31,
	2021				2020
Cash flows from operating activities:
Net income (loss)	$	138,175			$	(685,199	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		289,122				358,554
Stock-based compensation expense - equity awards		37,541				20,966
Stock-based compensation expense - liability awards		20,573				3,602
Impairment and abandonment expense		32,511				691,190
Exploratory dry hole costs		—				6,615
Deferred tax expense (benefit)		569				(85,124	)
Net (gain) loss on sale of long-lived assets		(34,168	)			(398	)
Non-cash portion of derivative (gain) loss		16,700				17,884
Amortization of debt issuance costs and debt discount		4,992				5,923
(Gain) loss on extinguishment of debt		22,156				(143,443	)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(21,475	)			44,572
(Increase) decrease in prepaid and other assets		2,907				(3,804	)
Increase (decrease) in accounts payable and other liabilities		16,016				(59,962	)
Net cash provided by operating activities		525,619				171,376
Cash flows from investing activities:
Acquisition of oil and natural gas properties		(6,510	)			(8,464	)
Drilling and development capital expenditures		(319,640	)			(318,465	)
Purchases of other property and equipment		(901	)			(1,083	)
Proceeds from sales of oil and natural gas properties		100,575				1,689
Net cash used in investing activities		(226,476	)			(326,323	)
Cash flows from financing activities:
Proceeds from borrowings under revolving credit facility		570,000				570,000
Repayment of borrowings under revolving credit facility		(875,000	)			(415,000	)
Proceeds from issuance of senior notes		170,000				—
Debt exchange and debt issuance costs		(6,421	)			(6,650	)
Premiums paid on capped call transactions		(14,688	)			—
Redemption of senior secured notes		(127,073	)			—
Proceeds from exercise of stock options		132				—
Restricted stock used for tax withholdings		(14,497	)			(607	)
Net cash (used in) provided by financing activities		(297,547	)			147,743
Net increase (decrease) in cash, cash equivalents and restricted cash		1,596				(7,204	)
Cash, cash equivalents and restricted cash, beginning of period		8,339				15,543
Cash, cash equivalents and restricted cash, end of period	$	9,935			$	8,339

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

	Year Ended December 31,
	2021			2020
Cash and cash equivalents	$	9,380		$	5,800
Restricted cash	$	555		$	2,539
Total cash, cash equivalents and restricted cash	$	9,935		$	8,339

Non-GAAP Financial MeasuresIn addition to disclosing financial results calculated in accordance with U.S. generally accepted accounting principles (“GAAP”), our earnings release contains non-GAAP financial measures as described below.

Adjusted EBITDAX

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income before interest expense, income taxes, depreciation, depletion and amortization, exploration and other expenses, impairment and abandonment expense, non-cash gains or losses on derivatives, stock-based compensation (not cash-settled), gain/loss on extinguishment of debt, gain/loss from the sale of assets and non-recurring items. Adjusted EBITDAX is not a measure of net income as determined by GAAP.

Our management believes Adjusted EBITDAX is useful as it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers, without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDAX to net income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP:

	Three Months Ended December 31,								Year Ended December 31,
(in thousands)	2021				2020				2021				2020
Adjusted EBITDAX reconciliation to net income:
Net income (loss) attributable to Class A Common Stock	$	160,751			$	(88,655	)		$	138,175			$	(682,837	)
Net income (loss) attributable to noncontrolling interest		—				—				—				(2,362	)
Interest expense		13,931				17,682				61,288				69,192
Income tax expense (benefit)		569				—				569				(85,124	)
Depreciation, depletion and amortization		75,863				74,832				289,122				358,554
Impairment and abandonment expense		6,400				40,561				32,511				691,190
(Gain) loss on extinguishment of debt		—				—				22,156				(143,443	)
Non-cash derivative (gain) loss		(44,790	)			18,987				16,700				17,884
Stock-based compensation expense(1)		5,594				8,111				56,320				23,045
Exploration and other expenses		3,185				7,625				7,883				18,355
Workforce reduction severance payments		—				—				—				3,466
Transaction costs		—				—				—				476
(Gain) loss on sale of long-lived assets		(34,422	)			(10	)			(34,168	)			(398	)
Proceeds from terminated sale of assets		—				—				(5,983	)			—
Adjusted EBITDAX	$	187,081			$	79,133			$	584,573			$	267,998

(1)   Includes stock-based compensation for equity awards and also for cash-based liability awards that have not yet been settled in cash, both of which relate to general and administrative employees only. Stock-based compensation amounts for geographical and geophysical personnel are included within the Exploration and other expenses line item.

Free Cash Flow (Deficit)

Free cash flow is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define free cash flow as net cash provided by operating activities before changes in working capital, less incurred capital expenditures.

Our management believes free cash flow is a useful indicator of the Company’s ability to internally fund its exploration and development activities and to service or incur additional debt, without regard to the timing of settlement of either operating assets and liabilities or accounts payable related to capital expenditures. The Company believes that this measure, as so adjusted, presents a meaningful indicator of the Company’s actual sources and uses of capital associated with its operations conducted during the applicable period. Our computations of free cash flow may not be comparable to other similarly titled measures of other companies. Free cash flow should not be considered as an alternative to, or more meaningful than, cash provided by operating activities as determined in accordance with GAAP or as indicator of our operating performance or liquidity.

Free cash flow is not a financial measure that is determined in accordance with GAAP. Accordingly, the following table presents a reconciliation of free cash flow to net cash provided by operating activities, which is the most directly comparable financial measure calculated and presented in accordance with GAAP:

	Three Months Ended December 31,								Year Ended December 31,
(in thousands)	2021				2020				2021				2020
Net cash provided by operating activities	$	192,487			$	41,144			$	525,619			$	171,376
Changes in working capital:
Accounts receivable		(21,523	)			3,567				21,475				(44,572	)
Prepaid and other assets		(1,104	)			979				(2,907	)			3,804
Accounts payable and other liabilities		1,433				16,855				(16,016	)			59,962
Discretionary cash flow		171,293				62,545				528,171				190,570
Less: total capital expenditures incurred		(86,500	)			(29,900	)			(321,500	)			(254,800	)
Free cash flow (deficit)	$	84,793			$	32,645			$	206,671			$	(64,230	)

The following table summarizes the approximate volumes and average contract prices of the hedge contracts the Company had in place as of December 31, 2021 and additional contracts entered into through February 18, 2022:

	Period		Volume (Bbls)		Volume (Bbls/d)		Wtd. Avg. Crude Price ($/Bbl)(1)
Crude oil swaps	January 2022 - March 2022		1,080,000		12,000		$65.03
	April 2022 - June 2022		1,092,000		12,000		65.28
	July 2022 - September 2022		782,000		8,500		65.46
	October 2022 - December 2022		690,000		7,500		65.63
	January 2023 - March 2023		225,000		2,500		73.51
	April 2023 - June 2023		227,500		2,500		73.25
	July 2023 - September 2023		92,000		1,000		72.98
	October 2023 - December 2023		92,000		1,000		72.98
	Period		Volume (Bbls)		Volume (Bbls/d)		Wtd. Avg. Collar Price Ranges ($/Bbl)(2)
Crude oil collars	January 2022 - March 2022		225,000		2,500		$63.60 - $74.30
	April 2022 - June 2022		227,500		2,500		63.20 - 72.41
	July 2022 - September 2022		184,000		2,000		75.00 - 89.05
	October 2022 - December 2022		184,000		2,000		75.00 - 89.05
	January 2023 - March 2023		225,000		2,500		70.00 - 81.36
	April 2023 - June 2023		227,500		2,500		70.00 - 81.36
	July 2023 - September 2023		138,000		1,500		70.00 - 80.17
	October 2023 - December 2023		138,000		1,500		70.00 - 80.17
	Period		Volume (Bbls)		Volume (Bbls/d)		Wtd. Avg. Differential ($/Bbl)(3)
Crude oil basis differential swaps	January 2022 - March 2022		538,500		5,983		$0.29
	April 2022 - June 2022		591,500		6,500		0.32
	July 2022 - September 2022		552,000		6,000		0.29
	October 2022 - December 2022		552,000		6,000		0.29
	Period		Volume (Bbls)		Volume (Bbls/d)		Wtd. Avg. Differential ($/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

_________________________

(1)   These crude oil swap transactions are settled based on the NYMEX WTI index price 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 index price 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	January 2022 - March 2022		2,700,000		30,000		$3.00
	April 2022 - June 2022		2,730,000		30,000		3.24
	July 2022 - September 2022		2,760,000		30,000		3.24
	October 2022 - December 2022		1,540,000		16,739		3.15
	Period		Volume (MMBtu)		Volume (MMBtu/d)		Wtd. Avg. Collar Price Ranges ($/MMBtu)(2)
Natural gas collars	January 2022 - March 2022		1,800,000		20,000		$3.15 - $4.65
	April 2022 - June 2022		1,820,000		20,000		3.50 - 3.97
	July 2022 - September 2022		1,840,000		20,000		3.50 - 3.97
	October 2022 - December 2022		2,450,000		26,630		3.87 - 5.06
	January 2023 - March 2023		2,700,000		30,000		4.00 - 5.42
	April 2023 - June 2023		910,000		10,000		3.00 - 4.09
	July 2023 - September 2023		920,000		10,000		3.00 - 4.09
	October 2023 - December 2023		920,000		10,000		3.17 - 4.74
	January 2024 - March 2024		910,000		10,000		3.25 - 5.06
	Period		Volume (MMBtu)		Volume (MMBtu/d)		Wtd. Avg. Differential ($/MMBtu)(3)
Natural gas basis differential swaps	January 2022 - March 2022		4,500,000		50,000		$(0.29)
	April 2022 - June 2022		1,820,000		20,000		(0.45)
	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		1,350,000		15,000		(0.85)
	April 2023 - June 2023		1,365,000		15,000		(0.85)
	July 2023 - September 2023		1,380,000		15,000		(0.85)
	October 2023 - December 2023		1,380,000		15,000		(0.85)

________________________

(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 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.

(3) 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.

The following table summarizes estimated proved reserves, pre-tax PV 10%, and standardized measure of discounted future cash flows for the periods indicated:

	December 31, 2021				December 31, 2020				December 31, 2019
Proved developed reserves:
Oil (MBbls)		77,973				70,716				74,842
Natural gas (MMcf)		326,223				279,556				237,791
NGL (MBbls)		30,318				31,672				32,743
Total proved developed reserves (MBoe)(1)		162,662				148,981				147,216
Proved undeveloped reserves:
Oil (MBbls)		75,480				79,776				75,317
Natural gas (MMcf)		250,782				248,231				264,639
NGL (MBbls)		25,265				28,773				34,499
Total proved undeveloped reserves (MBoe)(1)		142,542				149,921				153,923
Total proved reserves:
Oil (MBbls)		153,453				150,492				150,159
Natural gas (MMcf)		577,005				527,787				502,430
NGL (MBbls)		55,583				60,445				67,242
Total proved reserves (MBoe)(1)		305,204				298,902				301,139
Proved developed reserves %		53	%			50	%			49	%
Proved undeveloped reserves %		47	%			50	%			51	%
Reserve values (in millions):
Standard measure of discounted future net cash flows	$	3,396.3			$	1,184.7			$	2,062.4
Discounted future income tax expense		481.2				4.4				135.5
Total proved pre-tax PV 10%(2)	$	3,877.5			$	1,189.1			$	2,197.9

_______________________

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

(2) Total proved pre-tax PV 10% (“Pre-tax PV 10%”) is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, and it is derived from the standardized measure of discounted future net cash flows (the ‘‘Standardized Measure’’), which is the most directly comparable GAAP financial measure. Pre-tax PV 10% is computed on the same basis as the Standardized Measure but without deducting future income taxes. We believe Pre-tax PV 10% is a useful measure for investors when evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our Pre-tax PV 10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, Pre-tax PV 10% is not a substitute for the Standardized Measure. Our Pre-tax PV 10% and Standardized Measure do not purport to present the fair value of our proved oil, NGL and natural gas reserves.

Supplemental Measures

Organic Reserve Replacement Ratio

The Company uses the organic reserve replacement ratio as an indicator of the Company’s ability to replace the reserves that it has developed and to increase its reserves over time. The ratio is not a representation of value creation and has a number of limitations that should be considered. For example, the ratio does not incorporate the costs or timing of developing future reserves. The organic reserve replacement ratio of 149% is calculated as (a) our total 2021 proved reserve extensions and discoveries and revisions to previous estimates of 33.1 MMBoe divided by (b) the Company’s total 2021 production of 22.2 MMBoe. The ratio calculation excludes acquisitions and divestitures.

Proved Developed and Drill-Bit Finding and Development (“F&D”) Costs

The Company uses proved developed F&D cost and drill-bit F&D cost as indicators of capital efficiency, in that they measure the Company’s costs to add proved reserves on a per Boe basis. Both calculations exclude acquisitions and divestitures and are subject to limitations, including the uncertainty of future costs to develop the Company’s reserves.

Proved developed F&D of $7.65 per Boe is calculated as our total 2021 exploration and developments costs incurred of $309.7 million divided by the sum of (i) total proved developed reserve extensions and discoveries, (ii) transfers from proved undeveloped reserves at year-end 2020, and (iii) proved developed reserve revisions to previous estimates, which altogether totaled 40.5 MMBoe.

Drill-bit F&D of $9.36 per Boe is calculated as (a) our total 2021 exploration and developments costs incurred of $309.7 million divided by (b) the Company’s total 2021 proved reserve extensions and discoveries and revisions to previous estimates of 33.1 MMBoe.