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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 March 31, 2022
OR
☐ 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)
Delaware47-5381253
(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 classTrading Symbol(s)Name of each exchange on which registered
Common Stock, par value $0.0001 per shareCDEVThe 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 April 30, 2022, there were 284,992,650 shares of Common Stock, par value $0.0001 per share outstanding.


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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 1A. Risk Factors in this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, 2021 (the “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 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.
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
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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 2021 Annual Report.
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 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)
March 31, 2022December 31, 2021
ASSETS
Current assets
Cash and cash equivalents
$50,624 $9,380 
Accounts receivable, net
131,837 71,295 
Prepaid and other current assets
6,973 5,860 
Total current assets
189,434 86,535 
Property and Equipment
Oil and natural gas properties, successful efforts method
Unproved properties
1,032,096 1,040,386
Proved properties
4,742,872 4,623,726
Accumulated depreciation, depletion and amortization
(2,059,679)(1,989,489)
Total oil and natural gas properties, net
3,715,289 3,674,623
Other property and equipment, net11,774 11,197
Total property and equipment, net
3,727,063 3,685,820 
Noncurrent assets
Operating lease right-of-use assets
14,714 16,385 
Other noncurrent assets
27,321 15,854
TOTAL ASSETS
$3,958,532 $3,804,594 
LIABILITIES AND EQUITY
Current liabilities
  Accounts payable and accrued expenses
$178,940 $130,256 
Operating lease liabilities1,728 1,413 
Derivative instruments117,689 35,150 
Other current liabilities
1,370 1,080 
Total current liabilities
299,727 167,899
 Noncurrent liabilities
Long-term debt, net
801,203 825,565 
Asset retirement obligations
17,647 17,240 
Deferred income taxes
8,834 2,589 
Operating lease liabilities14,473 16,002 
Other noncurrent liabilities
45,571 24,579 
Total liabilities
1,187,455 1,053,874
Commitments and contingencies (Note 11)
Shareholders’ equity
Common stock, $0.0001 par value, 620,000,000 shares authorized; 294,135,384 shares issued and 284,991,150 shares outstanding at March 31, 2022 and 294,260,623 shares issued and 284,696,972 shares outstanding at December 31, 2021
29 29 
Additional paid-in capital3,017,572 3,013,017 
Retained earnings (accumulated deficit)(246,524)(262,326)
Total Shareholders' equity2,771,077 2,750,720 
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY$3,958,532 $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 March 31,
20222021
 Operating revenues
Oil and gas sales$347,277 $192,391 
Operating expenses
Lease operating expenses28,734 25,861 
Severance and ad valorem taxes25,051 12,583 
Gathering, processing and transportation expenses21,891 20,625 
Depreciation, depletion and amortization71,009 63,783 
General and administrative expenses30,603 25,256 
Impairment and abandonment expense2,627 9,200 
Exploration and other expenses2,307 1,095 
Total operating expenses182,222 158,403 
Net gain (loss) on sale of long-lived assets82 44 
Income (loss) from operations165,137 34,032 
Other income (expense)
Interest expense(13,154)(17,485)
Net gain (loss) on derivative instruments(129,523)(51,199)
Other income (expense)118 7 
Total other income (expense)
(142,559)(68,677)
Income (loss) before income taxes22,578 (34,645)
Income tax (expense) benefit(6,776)— 
Net income (loss)$15,802 $(34,645)
Income (loss) per share of Common Stock:
Basic$0.06 $(0.12)
Diluted$0.05 $(0.12)
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)
Three Months Ended March 31,
2022

2021
Cash flows from operating activities:
Net income (loss)$15,802 $(34,645)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization
71,009 63,783 
Stock-based compensation expense - equity awards
5,545 4,585 
Stock-based compensation expense - liability awards13,720 10,414 
Impairment and abandonment expense
2,627 9,200 
Deferred tax expense (benefit)
6,776 — 
Net (gain) loss on sale of long-lived assets(82)(44)
Non-cash portion of derivative (gain) loss86,645 28,313 
Amortization of debt issuance costs and debt discount1,492 1,847 
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable(53,824)(14,997)
(Increase) decrease in prepaid and other assets(415)(264)
Increase (decrease) in accounts payable and other liabilities10,825 4,154 
Net cash provided by operating activities160,120 72,346 
Cash flows from investing activities:
Acquisition of oil and natural gas properties
(1,928)(433)
Drilling and development capital expenditures
(81,156)(46,152)
Purchases of other property and equipment
(1,052)(181)
Proceeds from sales of oil and natural gas properties
48 168 
Net cash used in investing activities(84,088)(46,598)
Cash flows from financing activities:
Proceeds from borrowings under revolving credit facility
135,000 70,000 
Repayment of borrowings under revolving credit facility
(160,000)(240,000)
Proceeds from issuance of senior notes— 170,000 
Debt issuance costs
(8,530)(5,444)
Premiums paid on capped call transactions— (14,688)
Proceeds from exercise of stock options1 — 
Restricted stock used for tax withholdings (1,259)(477)
Net cash used in financing activities(34,788)(20,609)
Net increase (decrease) in cash, cash equivalents and restricted cash
41,244 5,139 
Cash, cash equivalents and restricted cash, beginning of period
9,935 8,339 
Cash, cash equivalents and restricted cash, end of period
$51,179 $13,478 
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) (continued)
(in thousands)
Three Months Ended March 31,
2022

2021
Supplemental cash flow information
Cash paid for interest
$8,903 $11,272 
Supplemental non-cash activity
Accrued capital expenditures included in accounts payable and accrued expenses
$63,483 $50,333 
Asset retirement obligations incurred, including revisions to estimates
145 24 
Reconciliation of cash, cash equivalents and restricted cash presented on the consolidated statements of cash flows for the periods presented:
Three Months Ended March 31,
20222021
Cash and cash equivalents
$50,624 $10,936 
Restricted cash(1)
555 2,542 
Total cash, cash equivalents and restricted cash
$51,179 $13,478 
(1)    Included in Prepaid and other current assets in the consolidated balance sheet as of March 31, 2022.


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

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CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)
(in thousands)


Common StockAdditional Paid-In CapitalRetained Earnings (Accumulated Deficit)Total Shareholders’ Equity
SharesAmount
Balance at December 31, 2021294,261 $29 $3,013,017 $(262,326)$2,750,720 
Restricted stock issued20 — — — — 
Restricted stock forfeited(52)— — — — 
Restricted stock used for tax withholding(150)— (1,259)— (1,259)
Stock option exercises3 — 1 — 1 
Issuance of Common Stock under Employee Stock Purchase Plan53 — 268 — 268 
Stock-based compensation - equity awards— — 5,545 — 5,545 
Net income (loss)— — — 15,802 15,802 
Balance at March 31, 2022294,135 29 $3,017,572 $(246,524)$2,771,077 

Balance at December 31, 2020290,646 $29 $3,004,433 $(400,501)$2,603,961 
Restricted stock forfeited(1)— — — — 
Restricted stock used for tax withholding(128)— (477)— (477)
Issuance of Common Stock under Employee Stock Purchase Plan276 — 167 — 167 
Stock-based compensation - equity awards— — 4,585 — 4,585 
Capped call premiums— — (14,688)— (14,688)
Net income (loss)— — — (34,645)(34,645)
Balance at March 31, 2021290,793 29 $2,994,020 $(435,146)$2,558,903 

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

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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 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, 2021 (the “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 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.
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. There were no significant changes in operating leases during the three months ended March 31, 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.
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.
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 2—Accounts Receivable, Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
(in thousands)
March 31, 2022December 31, 2021
Accrued oil and gas sales receivable, net
$109,689 $57,287 
Joint interest billings, net
20,882 12,449 
Other
1,266 1,559 
Accounts receivable, net
$131,837 $71,295 
Accounts payable and accrued expenses are comprised of the following:
(in thousands)
March 31, 2022December 31, 2021
Accounts payable
$38,520 $9,736 
Accrued capital expenditures
37,305 24,377
Revenues payable
46,004 40,438
Accrued employee compensation and benefits
5,791 17,218
Accrued interest
18,628 15,259
Accrued derivative settlements payable
18,715 8,591
Accrued expenses and other
13,977 14,637
Accounts payable and accrued expenses
$178,940 $130,256 
Note 3—Long-Term Debt
The following table provides information about the Company’s long-term debt as of the dates indicated:
(in thousands)
March 31, 2022December 31, 2021
Credit Facility due 2027
$— $25,000 
Senior Notes
5.375% Senior Notes due 2026
289,448 289,448 
6.875% Senior Notes due 2027
356,351 356,351 
3.25% Convertible Senior Notes due 2028
170,000 170,000 
Unamortized debt issuance costs on Senior Notes
(12,719)(13,279)
Unamortized debt discount
(1,877)(1,955)
Senior Notes, net801,203 800,565 
Total long-term debt, net
$801,203 $825,565 
Credit Agreement
On February 18, 2022, CRP, the Company’s consolidated subsidiary, entered into an amended and restated five-year secured credit facility (the “Credit Agreement”) with a syndicate of banks, which replaced our previous credit facility that was set to mature in May 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 March 31, 2022, the Company had no borrowings outstanding and $744.2 million in available borrowing capacity, which was net of $5.8 million in letters of credit outstanding, under its new facility.
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The amount available to be borrowed under the Credit Agreement is equal to the lesser of (i) the borrowing base, (ii) aggregate elected commitments, which is set at $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 two optional borrowing base redeterminations 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 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.
Borrowings under the Credit Agreement may be base rate loans or Secured Overnight Financing Rate (“SOFR”) loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans. SOFR loans bear interest at SOFR plus an applicable margin ranging from 225 to 325 basis points, depending on the percentage of 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 Term SOFR rate for a one-month interest period plus 100 basis points, plus an applicable margin, ranging from 125 to 225 basis points, depending on the percentage of the borrowing base utilized. CRP also pays a commitment fee of 37.5 to 50 basis points on unused elected commitment amounts under its facility.
The Credit Agreement provides for, among other things, the ability to repurchase outstanding shares of the Company’s Class A common stock (the “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 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 redeem junior debt; (vi) enter into commodity hedges exceeding a specified percentage of our expected production; (vii) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates.
The Credit Agreement also requires it to maintain compliance with the following financial ratios:
(i) a current ratio, which is the ratio of CRP’s consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and
(ii) a leverage ratio, as defined within the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the prior four fiscal quarters, of not greater than 3.5 to 1.0.
CRP was in compliance with the covenants and the applicable financial ratios described above as of March 31, 2022.
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.
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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.
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 March 31, 2022, the net liability recorded related to the Convertible Senior Notes was $164.4 million.
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.
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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.
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, $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, which were fully redeemed at par in connection with the Convertible Senior Notes issuance during the second quarter of 2021. As of March 31, 2022, the remaining aggregate principal amount of 2027 Senior Notes and 2026 Senior Notes outstanding was $356.4 million and $289.4 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 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.
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 March 31, 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.
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 4—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 three months ended March 31, 2022:
(in thousands)
Asset retirement obligations, beginning of period
$17,240 
Liabilities incurred
237 
Liabilities divested and settled
— 
Accretion expense
262 
Revisions to estimated cash flows
(92)
Asset retirement obligations, end of period
$17,647 
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.

Note 5—Stock-Based Compensation
On October 7, 2016, the stockholders of the Company approved the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the “LTIP”), 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 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.
The following table summarizes stock-based compensation expense recognized for the periods presented:
Three Months Ended March 31,
(in thousands)20222021
Equity Awards
Restricted stock$3,439 $3,606 
Stock option awards31 271 
Performance stock units2,003 639 
Other stock-based compensation expense(1)
72 69 
Total stock-based compensation - equity awards5,545 4,585 
Liability Awards
Restricted stock units— 3,308 
Performance stock units13,720 7,106 
Total stock-based compensation - liability awards13,720 10,414 
Total stock-based compensation expense$19,265 $14,999 
(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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 three months ended March 31, 2022:
Restricted StockWeighted Average Fair Value
Unvested balance as of December 31, 202110,143,687 $2.85 
Granted20,129 6.45 
Vested(387,929)5.03 
Forfeited(67,438)5.51 
Unvested balance as of March 31, 20229,708,449 2.75 
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. The total fair value of restricted stock that vested during the three months ended March 31, 2022 and 2021 was $2.0 million and $2.6 million, respectively. Unrecognized compensation cost related to restricted shares that were unvested as of March 31, 2022 was $18.1 million, which the Company expects to recognize over a weighted average period of 2.0 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 following table provides information about stock option awards outstanding during the three months ended March 31, 2022:
OptionsWeighted Average Exercise PriceWeighted Average Remaining Term
(in years)		Aggregate Intrinsic Value
(in thousands)
Outstanding as of December 31, 20212,212,798 $15.31 
Granted— — 
Exercised(2,500)0.25 $18 
Forfeited(2,500)7.58 
Expired(25,832)16.72 
Outstanding as of March 31, 20222,181,966 15.32 5.10$496 
Exercisable as of March 31, 20222,109,122 15.71 5.10$194 
The total fair value of stock options that vested during the three months ended March 31, 2022 and 2021 was $0.2 million and $0.3 million, respectively. The intrinsic value of the stock options exercised was minimal for the three months ended March 31, 2022 and there were no stock options exercised for the three months ended March 31, 2021. As of March 31, 2022, there was $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 0.7 years.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 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.
During the three months ended March 31, 2022 and 2021 there was no PSU activity. As of March 31, 2022, there was $11.0 million of unrecognized compensation cost related to PSUs that were unvested, which the Company expects to recognize on a pro-rata basis over a weighted average period of 2.3 years.
Liability Awards
The Company has performance stock units that were granted under the LTIP, which 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 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 associated 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 were settleable in cash upon vesting. The restricted stock units 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 could vest immediately, on an accelerated basis, if they meet certain market-based vesting criteria equal to the maximum return percentage for at least 20 out of any 30 consecutive trading days. Additionally, the restricted stock units 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.
During the second quarter of 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 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 year ended December 31, 2021. There are no remaining restricted stock units outstanding as of March 31, 2022.
Performance Stock Units
The Company granted 5.5 million 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 March 31, 2022, there was $28.3 million of unrecognized compensation cost that represents the unvested portion of the fair value of the PSUs at March 31, 2022 and will be recognized over a weighted average period of 1.3 years.
Liability Awards Fair Value
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The fair value of the 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 March 31, 2022:
Performance stock units
Number of simulations10,000,000
Expected implied stock volatility65.2%
Dividend yield—%
Risk-free interest rate1.8%
Note 6—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 March 31, 2022:
PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Crude Price
($/Bbl)(1)
Crude oil swaps
April 2022 - June 20221,092,000 12,000 $65.28
July 2022 - September 2022782,000 8,500 65.46
October 2022 - December 2022690,000 7,500 65.63
January 2023 - March 2023225,000 2,500 73.51
April 2023 - June 2023227,500 2,500 73.25
July 2023 - September 202392,000 1,000 72.98
October 2023 - December 202392,000 1,000 72.98
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Collar Price Ranges
($/Bbl)(2)
Crude oil collars
NYMEX WTIApril 2022 - June 2022227,500 2,500 $63.20-$72.41
July 2022 - September 2022276,000 3,000 75.00-92.46
October 2022 - December 2022276,000 3,000 75.00-92.46
January 2023 - March 2023405,000 4,500 72.22-84.08
April 2023 - June 2023409,500 4,500 72.22-84.08
July 2023 - September 2023230,000 2,500 72.00-82.78
October 2023 - December 2023230,000 2,500 72.00-82.78
ICE BrentApril 2022 - June 202291,000 1,000 $90.00-$105.20

PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(3)
Crude oil basis differential swaps
April 2022 - June 2022637,000 7,000 $0.34
July 2022 - September 2022552,000 6,000 0.29
October 2022 - December 2022552,000 6,000 0.29

PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(4)
Crude oil roll differential swaps
April 2022 - June 2022910,000 10,000 $0.71
July 2022 - September 2022920,000 10,000 0.71
October 2022 - December 2022920,000 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 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.

PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Gas Price
($/MMBtu)(1)
Natural gas swaps
April 2022 - June 20222,730,000 30,000 $3.24
July 2022 - September 20222,760,000 30,000 3.24
October 2022 - December 20221,540,000 16,739 3.15
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Differential
($/MMBtu)(2)
Natural gas basis differential swaps
April 2022 - June 20221,820,000 20,000 $(0.45)
July 2022 - September 20221,840,000 20,000 (0.45)
October 2022 - December 20221,840,000 20,000 (0.45)
January 2023 - March 20231,350,000 15,000 (0.85)
April 2023 - June 20231,365,000 15,000 (0.85)
July 2023 - September 20231,380,000 15,000 (0.85)
October 2023 - December 20231,380,000 15,000 (0.85)
PeriodVolume (MMBtu)Volume
(MMBtu/d)
Wtd. Avg. Collar Price Ranges
($/MMBtu)(3)
Natural gas collars
April 2022 - June 20221,820,000 20,000 $3.50-$3.97
July 2022 - September 20221,840,00020,000 3.50-3.97
October 2022 - December 20222,450,00026,630 3.87-5.06
January 2023 - March 20232,700,00030,000 4.00-5.42
April 2023 - June 20231,820,00020,000 3.13-4.05
July 2023 - September 20231,840,00020,000 3.13-4.05
October 2023 - December 20231,840,00020,000 3.21-4.89
January 2024 - March 20241,820,00020,000 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.
(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 March 31,
(in thousands)
20222021
Net gain (loss) on derivative instruments
$(129,523)$(51,199)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 ClassificationGross Fair Value Asset/Liability Amounts
Gross Amounts Offset(1)
Net Recognized Fair Value Assets/Liabilities
(in thousands)
March 31, 2022
Derivative Assets
Commodity contracts
Prepaid and other current assets$10,541 $(9,388)$1,153 
Other noncurrent assets13,238 (11,040)2,198 
Derivative Liabilities
Commodity contracts
Derivative instruments127,077 (9,388)117,689 
Other noncurrent liabilities18,257 (11,040)7,217 
December 31, 2021
Derivative Assets
Commodity contracts
Prepaid and other current assets$3,284 $(3,284)$— 
Other noncurrent assets585$(345)240
Derivative Liabilities
Commodity contracts
Derivative instruments$38,434 $(3,284)$35,150 
Other noncurrent liabilities345 (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 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. The Company enters into new hedge arrangements only with participants 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.
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 Agreement as referenced above.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 7—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 1Level 2Level 3
March 31, 2022
Total assets
$— $3,351 $— 
Total liabilities
— 124,906 — 
December 31, 2021
Total assets
$— $240 $— 
Total liabilities
— 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.
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 which the carrying amount of proved properties exceeds their estimated fair value. The Company reviews its oil and natural gas properties on a field-by-field basis.
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The Company calculates the estimated fair values of its oil and natural gas properties using an income 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 4—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 are accounted for at cost. The following table summarizes the carrying values, principal amounts and fair values of these instruments as of the dates indicated:
March 31, 2022December 31, 2021
Carrying ValuePrincipal AmountFair ValueCarrying ValuePrincipal AmountFair value
Credit Facility due 2027(1)
$— $— $— $25,000 $25,000 $25,000 
5.375% Senior Notes due 2026(2)
285,874 289,448 280,765 285,666 289,448 286,554 
6.875% Senior Notes due 2027(2)
350,936 356,351 356,351 350,712 356,351 361,696 
3.25% Convertible Notes due 2028(2)
164,393 170,000 258,977 164,187 170,000 215,279 
(1)     The carrying values of the amounts outstanding under CRP’s Credit Agreement approximate fair value because its variable interest rates are tied to current market rates and the applicable credit spreads represent current market rates for the credit risk profile of the Company.
(2)    The 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 8—Shareholders' Equity
Stock Repurchase Program
In February 2022, the Company’s Board of 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 three months ended March 31, 2022.
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 9—Earnings Per Share
Basic earnings per share (“EPS”) is calculated by dividing net income by the weighted average shares of Common Stock outstanding during each period. Diluted EPS is calculated by dividing adjusted net income 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 treasury stock method, and (ii) potential shares issuable under our Convertible Senior Notes, using the “if-converted” method, which is net of tax.
The following table reflects the EPS computations for the periods indicated based on a weighted average number of common shares outstanding each period:
Three Months Ended March 31,
(in thousands, except per share data)20222021
Net income (loss) $15,802 $(34,645)
Add: Interest on Convertible Senior Notes, net of tax1,293 — 
Adjusted net income (loss) $17,095 $(34,645)
Basic weighted average shares of Common Stock outstanding284,851 278,935 
Add: Dilutive effects of equity awards and ESPP shares7,755 — 
Add: Dilutive effects of Convertible Senior Notes27,074 — 
Diluted weighted average shares of Common Stock outstanding319,680 278,935 
Basic net earnings (loss) per share of Common Stock$0.06 $(0.12)
Diluted net earnings (loss) per share of Common Stock$0.05 $(0.12)
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 March 31,
(in thousands)2022
2021(1)
Out-of-the-money stock options2,097 2,294 
Restricted stock— 9,565 
Performance stock units449 399 
Employee Stock Purchase Plan— 41 
Convertible Senior Notes— 27,074 
Warrants— 8,000 
(1)    The Company recognized a net loss during the three months ended March 31, 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—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 March 31,
(in thousands)20222021
Oil and gas sales$9,483 $1,075 
Gathering, processing and transportation expenses2,519 1,205 
(in thousands)March 31, 2022December 31, 2021
Accounts receivable, net(1)
$5,220 $5,562 
(1) Represents amounts due from Lucid and are presented net of unpaid processing fees as of the indicated period end date.

Note 11—Commitments and Contingencies
Commitments
The Company routinely enters into, extends or amends operating agreements in the ordinary course of business. During the three months ended March 31, 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 $44.6 million, which represents the minimum financial commitment pursuant to the terms of the contract as of March 31, 2022. There have been no other material, non-routine changes in commitments during the three months ended March 31, 2022. Please refer to Note 13—Commitments and Contingencies included in Part II, Item 8 in the Company’s 2021 Annual Report.
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.
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.
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 12—Revenues
Revenue from Contracts with Customers
Crude oil, natural gas and NGL sales are recognized at the point that control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials. As a result, the Company’s realized 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 March 31,
20222021
Operating revenues (in thousands):
Oil sales
$262,767 $133,726 
Natural gas sales
39,018 35,451 
NGL sales
45,492 23,214 
Oil and gas sales
$347,277 $192,391 
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.
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 March 31, 2022 and December 31, 2021, such receivable balances were $109.7 million and $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 months ended March 31, 2022 and 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
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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—Subsequent Events
Amendment to LTIP
On April 27, 2022, the shareholders of the Company approved the amended and restated LTIP, which, among other things, increased the number of shares of Common Stock authorized for issuance from 24,750,000 shares to 44,250,000 shares.
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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, continued and future impacts of COVID-19 and other uncertainties, as well as those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements” and under the heading “Item 1A. Risk Factors” in our 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. 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 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 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 demand for oil and natural gas has been significantly impacted by the worldwide outbreak of COVID-19, specifically regarding the uncertainty surrounding the virus’s impact and because of various governmental actions taken to mitigate the spread of the virus. Concurrently, global oil and natural gas supplies have been disrupted by production curtailment agreements among the Organization of Petroleum Exporting Countries and other oil producing countries (“OPEC+”) and reduced drilling and completion activity from U.S. producers. Both OPEC+ output and U.S. drilling activity has increased since 2020 levels; however, these factors have only led to a gradual increase in oil and gas supply, and global supply has not returned to pre-pandemic levels. Further in the first quarter 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, fewer government mandated restrictions and the global-wide transition away from coal to natural gas. As a result, 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 throughout 2021 and have led to heightened commodity prices in the first quarter of 2022. Specifically, WTI spot prices for crude oil reached a high of $123.70 per barrel on March 8, 2022, from a low of negative $37.63 per barrel on April 20, 2020. Similarly, the Henry Hub index price for natural gas reached a high of $6.44 on February 3, 2022, from a low of $1.33 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 2020:
202020212022
Q1Q2Q3Q4Q1Q2Q3Q4Q1
Crude oil (per Bbl)$46.19 $28.00 $40.93 $42.66 $57.84 $66.06 $70.56 $77.09 $94.40 
Natural gas (per MMBtu)$1.88 $1.65 $1.95 $2.47 $3.44 $2.88 $4.28 $4.74 $4.60 
Lower commodity prices (including realized price differentials) and lower futures curves for oil and gas prices can result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, 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 immediately repay a portion of the debt outstanding under the credit agreement. Additionally, lower prices can affect our operations, which could impact our ability to comply with the covenants under our credit agreement and senior notes.
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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 into 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 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 and have followed the Center of Disease Control (the “CDC”) recommended preventive measures to limit the spread of COVID-19. We have continued to update our safety protocols in alignment with CDC guidance and government mandates. We have not experienced any significant operational disruptions, including disruptions from our suppliers or service providers, as a result of the COVID-19 outbreak.
2022 Highlights and Future Considerations
Operational Highlights
We operated a two-rig drilling program during the first three months of 2022, which enabled us to complete and bring online 18 gross operated wells with an average effective lateral length of approximately 8,500 feet.
Financing Highlights
On February 18, 2022, we 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 $350 million of our outstanding Class A common stock (“Common Stock”), which program is approved to run through April 1, 2024 (the “Repurchase Program”). We intend to use the Repurchase Program to reduce shares of our Common Stock outstanding and plan to fund these share repurchases with cash on hand and cash flows from operations.
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Results of Operations
Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021
The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes:
Three Months Ended March 31,Increase/(Decrease)
20222021$%
Net revenues (in thousands):
Oil sales$262,767 $133,726 $129,041 96 %
Natural gas sales39,018 35,451 3,567 10 %
NGL sales45,492 23,214 22,278 96 %
Oil and gas sales$347,277 $192,391 $154,886 81 %
Average sales prices:
Oil (per Bbl)$89.17 $52.62 $36.55 69 %
Effect of derivative settlements on average price (per Bbl)(12.82)(9.43)(3.39)(36)%
Oil net of hedging (per Bbl)
$76.35 $43.19 $33.16 77 %
Average NYMEX price for oil (per Bbl)$94.40 $57.84 $36.56 63 %
Oil differential from NYMEX(5.23)(5.22)(0.01)— %
Natural gas (per Mcf)$3.93 $3.79 $0.14 4 %
Effect of derivative settlements on average price (per Mcf)(0.51)0.12 (0.63)(525)%
Natural gas net of hedging (per Mcf)
$3.42 $3.91 $(0.49)(13)%
Average NYMEX price for natural gas (per Mcf)$4.60 $3.44 $1.16 34 %
Natural gas differential from NYMEX(0.67)0.35 (1.02)(291)%
NGL (per Bbl)$49.37 $29.78 $19.59 66 %
Net production:
Oil (MBbls)2,947 2,542 405 16 %
Natural gas (MMcf)9,925 9,343 582 6 %
NGL (MBbls)921 780 141 18 %
Total (MBoe)(1)
5,522 4,878 644 13 %
Average daily net production:
Oil (Bbls/d)32,741 28,239 4,502 16 %
Natural gas (Mcf/d)110,280 103,806 6,474 6 %
NGL (Bbls/d)10,238 8,662 1,576 18 %
Total (Boe/d)(1)
61,359 54,202 7,157 13 %
(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 March 31, 2022 were $154.9 million (or 81%) higher than total net revenues for the three months ended March 31, 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 first quarter of 2022 compared to the same 2021 period by 69%, 4% and 66%, respectively. The 69% increase in the average realized oil price was mainly the result of higher (63%) NYMEX crude prices between periods. The average realized sales price of natural gas increased 4% due to higher (34%) NYMEX gas prices between periods, partially offset by wider gas differentials ($1.02 per Mcf wider). The 66% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in the first quarter of 2022 as compared to the first quarter of 2021. The market prices for oil, natural gas and NGLs have all been impacted by higher global supply constraints for oil and gas throughout 2021 and 2022 as discussed in the market conditions section above.
Net production volumes for oil, natural gas and NGLs increased 16%, 6% and 18%, respectively, between periods. The oil production volume increase resulted from our successful drilling program in the Delaware Basin. Since the first quarter of 2021, we placed 49 wells on production, which added 1,348 MBbls of net oil production to the three months ended March 31, 2022 as compared to 20 wells brought online since the first quarter of 2020 that added 422 MBbls of net oil production to the first quarter of 2021. These oil volume increases were partially offset by normal field production declines across our existing wells. Natural gas and NGLs are produced concurrently with our crude oil volumes, which typically results in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. However, as the majority of our wells drilled since the first quarter of 2021 have been in New Mexico, this has resulted in fewer gas and NGL volumes being produced relative to oil volumes because our New Mexico wells have a lower gas-to-oil ratio (“GOR”) than our Texas wells do. Additionally, the main processor of our raw gas in New Mexico operated in partial ethane-recovery during the first quarter of 2022, as compared to operating in full ethane-rejection during the 2021 period, and this resulted in fewer natural gas volumes and more NGLs being recovered from our wet gas stream during the 2022 period.
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
Three Months Ended March 31,Increase/(Decrease)
20222021Change%
Operating costs (in thousands):
Lease operating expenses$28,734 $25,861 $2,873 11 %
Severance and ad valorem taxes25,051 12,583 12,468 99 %
Gathering, processing and transportation expenses21,891 20,625 1,266 6 %
Operating cost metrics:
Lease operating expenses (per Boe)$5.20 $5.30 $(0.10)(2)%
Severance and ad valorem taxes (% of revenue)7.2 %6.5 %0.7 %10 %
Gathering, processing and transportation expenses (per Boe)$3.96 $4.23 $(0.27)(6)%
Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended March 31, 2022 increased $2.9 million compared to the three months ended March 31, 2021. Higher LOE for the first quarter of 2022 was primarily related to (i) higher chemical costs for treating natural gas; (ii) an increase in workover expense between periods; and (iii) higher fixed and variable costs associated with our higher well count, which increased to 422 gross operated horizontal wells as of March 31, 2022 from 397 gross operated horizontal wells as of March 31, 2021. These increases were partially offset by lower electricity costs between periods due to the high electricity charges incurred in the first quarter of 2021 as a result of the severe winter storm in the Permian Basin (“Winter Storm Uri”) in February of 2021.
LOE per Boe was $5.20 for the first quarter of 2022, which represents a decrease of $0.10 per Boe (or 2%) from the first quarter of 2021. This decrease was primarily driven by per Boe decreases associated with (i) lower electricity expenses between periods (discussed above); and (ii) fixed and semi-variable costs, such as monthly equipment rentals and water handling costs, that don’t increase at the same rate as increases in production. These per Boe decreases were partially offset by increases in the operating costs described above.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended March 31, 2022 increased $12.5 million compared to the three months ended March 31, 2021. Severance taxes are 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 first quarter of 2022 increased $11.5 million compared to the same 2021 period primarily due to higher oil, natural gas and NGL revenues between periods. Ad valorem taxes between periods also increased $1.0 million due to 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 increased to 7.2% for the three months ended March 31, 2022 as compared to 6.5% for the same prior year quarter. This increase in rate was the result of a larger portion of our oil and gas volumes being produced in New Mexico during the first quarter of 2022, and New Mexico levies higher severance tax rates than Texas.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended March 31, 2022 increased $1.3 million as compared to the three months ended March 31, 2021. This increase is mainly due to (i) 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 discussed above, and (ii) a $3.6 million decrease in reimbursements from third parties for their usage of our available firm transport capacity. These increases were partially offset by a decrease in demand fees between periods, as the first quarter of 2021 was heavily impacted by excess demand charges during Winter Storm Uri that did not reoccur in the comparable 2022 period.
On a per Boe basis, GP&T decreased from $4.23 for the first quarter of 2021 to $3.96 for the first quarter of 2022. As discussed above, a higher portion of our 2022 total oil and gas volumes were produced from our wells in New Mexico, where our GP&T rates are lower than those incurred in Texas, and this in turn resulted in a lower total GP&T rate between periods.
Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A”) for the periods indicated: 
Three Months Ended March 31,
(in thousands, except per Boe data)2022

2021
Depreciation, depletion and amortization$71,009 $63,783 
Depreciation, depletion and amortization per Boe$12.86 $13.08 
For the three months ended March 31, 2022, DD&A expense amounted to $71.0 million, an increase of $7.2 million over the same 2021 period. The primary factor contributing to higher DD&A expense in 2022 was the increase in our overall production volumes between periods, which increased DD&A expense by $8.4 million for the three months ended March 31, 2022. This was partially offset by our lower DD&A rates, which decreased DD&A expense by $1.2 million 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 $12.86 for the first quarter of 2022 compared to $13.08 for the same period in 2021. This decrease in DD&A rate was primarily due to net upward revisions in our proved developed reserves since the first quarter of 2021 mainly related to higher SEC reserve pricing between periods.
General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:
Three Months Ended March 31,
(in thousands)20222021
Cash general and administrative expenses$11,769 $10,632 
Stock-based compensation - equity awards5,114 4,377 
Stock-based compensation - liability awards13,720 10,247 
General and administrative expenses$30,603 $25,256 
G&A expenses for the three months ended March 31, 2022 were $30.6 million compared to $25.3 million for the three months ended March 31, 2021. Higher G&A in the first quarter of 2022 was the result of a $4.2 million increase in total stock-based compensation expense between periods. This increase was primarily related to performance stock unit grants in 2020 and 2021 that are recorded at their respective fair values each balance sheet date, and such fair values increased between periods. In addition, cash G&A increased $1.2 million period over period due to higher payroll and other personnel costs.
Impairment and Abandonment Expense. During the three months ended March 31, 2022, impairment and abandonment expense was $2.6 million as compared to $9.2 million during the three months ended March 31, 2021. Both periods consisted solely of 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:
Three Months Ended March 31,
(in thousands)2022

2021
Geological and geophysical costs$1,703 $613 
Stock-based compensation - equity awards431 208 
Stock-based compensation - liability awards— 167 
Other expenses 173 107 
Exploration and other expenses$2,307 $1,095 
Exploration and other expenses were $2.3 million for the three months ended March 31, 2022 compared to $1.1 million for the three months ended March 31, 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 period over period increase was primarily related to higher G&G personnel costs in the first quarter of 2022.
Interest Expense. The following table summarizes our interest expense for the periods indicated:
Three Months Ended March 31,
(in thousands)
20222021
Credit facility$877 $3,315 
8.00% Senior Secured Notes due 2025
— 2,541 
5.375% Senior Notes due 20263,889 3,889 
6.875% Senior Notes due 20276,125 6,125 
3.25% Convertible Senior Notes due 20281,381 172 
Amortization of debt issuance costs and debt discount1,492 1,847 
Interest capitalized(610)(404)
Total$13,154 $17,485 
Interest expense decreased $4.3 million for the three months ended March 31, 2022 as compared to the three months ended March 31, 2021 primarily due to (i) $2.5 million in interest expense on our Senior Secured Notes due 2025 that was incurred in the first quarter of 2021 but not in the 2022 period, as these notes were redeemed in April of 2021, and (ii) $2.4 million in lower interest incurred on our Credit Agreement due to lower borrowings outstanding during the 2022 period. These decreases were partially offset by interest on our Convertible Senior Notes that was incurred in 2022 but only partially in the 2021 period due to their issuance in March of 2021.
Our weighted average borrowings outstanding under our Credit Agreement were $27.7 million versus $330.9 million for the three months ended March 31, 2022 and 2021, respectively. Our Credit Agreement’s weighted average effective interest rate was 2.9% and 3.5% for the three months ended March 31, 2022 and 2021, respectively.
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.
The following table presents gains and losses on our derivative instruments for the periods indicated:
Three Months Ended March 31,
(in thousands)
20222021
Realized cash settlement gains (losses)
$(42,878)$(22,886)
Non-cash mark-to-market derivative gain (loss)
(86,645)(28,313)
Total
$(129,523)$(51,199)
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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:
Three Months Ended March 31,
(in thousands)
20222021
Income (loss) before income taxes
$22,578 $(34,645)
Income tax (expense) benefit
(6,776)— 
Our provisions for income taxes for the three months ended March 31, 2022 and 2021 differs from the amounts that would be provided by applying the U.S. federal statutory rate of 21% to pre-tax book income (loss) primarily due to (i) permanent differences, (ii) state income taxes, and (iii) any changes during the period in our deferred tax asset valuation allowance.
For the three months ended March 31, 2022, we generated pre-tax net income of $22.6 million and recorded income tax expense of $6.8 million. The primary factor increasing our income tax expense in excess of the U.S. statutory rate was a non-recurring change in our state apportionment rate that was reflected in the current quarter.
For the three months ended March 31, 2021, we recognized a deferred tax asset valuation allowance of $12.4 million against net operating losses (“NOLs”) generated during the quarter. This change in our valuation allowance was the primary factor reducing our income tax benefit to zero for the first quarter of 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. 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 three months ended March 31, 2022:
(in millions)Three Months Ended March 31, 2022
Drilling, completion and facilities$111.6 
Infrastructure, land and other 3.1 
Total capital expenditures incurred$114.7 
    We continually evaluate our capital needs and compare them to our capital resources. We operated a two-rig drilling program during the first three months of 2022 and plan to continue with two rigs for the remainder of the year. We expect our total capex budget for 2022 to be between $365 million to $425 million, of which $350 million to $400 million is allocated to drilling, completion and facilities activity. We funded our capital expenditures for the three months ended March 31, 2022 entirely from cash flows from operations, and we expect to fund the remainder of our 2022 capex budget entirely from cash flows from operations as well, given our anticipated level of oil and gas production, current commodity prices and our commodity hedge positions in place. We were free cash flow positive during the first three months of 2022 such that we were able to pay down all of our borrowings under our Credit Agreement during the period. Based upon current commodity prices combined with our low cost structure, we expect to continue to generate free cash flow during the remainder of 2022, which will allow us to fund our planned operational activities with minimal or no borrowings under our Credit Agreement. 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 or otherwise.
    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 and other agreements and other factors.
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.
Analysis of Cash Flow Changes
The following table summarizes our cash flows for the periods indicated:
Three Months Ended March 31,
(in thousands)20222021
Net cash provided by operating activities$160,120 $72,346 
Net cash used in investing activities(84,088)(46,598)
Net cash used in financing activities(34,788)(20,609)
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For the three months ended March 31, 2022, we generated $160.1 million of cash from operating activities, an increase of $87.8 million from the same period in 2021. Cash provided by operating activities increased primarily due to higher realized prices for all commodities, higher production volumes, decreased cash interest costs, and the timing of our supplier payments during the three months ended March 31, 2022. These increasing factors were partially offset by higher lease operating expenses, GP&T, cash G&A, severance and ad valorem taxes, cash settlement losses on derivatives, and the timing of our receivable collections for the three months ended March 31, 2022 as compared to the same 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 costs between periods.
During the three months ended March 31, 2022, cash flows from operating activities were used to finance $81.2 million of drilling and development cash expenditures and repay net borrowings of $25.0 million under our Credit Agreement.
During the three months ended March 31, 2021, cash flows from operating activities and net proceeds from the issuance of the Convertible Senior Notes (defined below) were used to finance $46.2 million of drilling and development cash expenditures, repay net borrowings of $170.0 million under our credit facility and to fund $14.7 million in capped call spread transactions.
Credit Agreement
On February 18, 2022, CRP entered into an amended and restated five-year secured Credit Agreement with a syndicate of banks, which replaced our previous credit facility that was set to mature in May 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 March 31, 2022, the Company had no borrowings outstanding and $744.2 million in available borrowing capacity, which was net of $5.8 million in letters of credit outstanding, under its new facility.
The 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 conditions and subject to the requirement that such repurchases are funded from our free cash flow. The Credit Agreement contains restrictive covenants that limit 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 redeem junior debt; (vi) enter into commodity hedges exceeding a specified percentage of our expected production; (vii) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates.
The Credit Agreement also requires it to maintain compliance with the following financial ratios:
(i) a current ratio, which is the ratio of CRP’s consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and
(ii) a leverage ratio, as defined within the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the prior four fiscal quarters, of not greater than 3.5 to 1.0.
CRP was in compliance with the covenants and the applicable financial ratios described above as of March 31, 2022 and through the filing of this Quarterly Report.
For further information on the Credit Agreement, refer to Note 3—Long-Term Debt under Part I, Item I of this Quarterly Report.
Convertible Senior Notes
On March 19, 2021, CRP issued $150.0 million 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 notes. 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 (defined below), which was the intended use of proceeds from the Convertible Senior Notes offering.
The Convertible Senior 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 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 3—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
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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 (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 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 March 31, 2022 and through the filing of this Quarterly Report.
For further information on our Convertible Senior Notes and Senior Unsecured Notes, refer to Note 3—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 or extend. Since December 31, 2021, there have not been any significant, non-routine changes in our contractual obligations other than the new frac’ sand agreements entered into as discussed in Note 11—Commitments and Contingencies under Part I, Item I of this Quarterly Report.
Critical Accounting Policies and Estimates
There have been no material changes during the three months ended March 31, 2022 to the critical accounting 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 2021 Annual Report for a discussion of our critical accounting policies and estimates.
New Accounting Pronouncements
There were no significant new accounting standards adopted or new accounting pronouncements that would have potential effects to us as of March 31, 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 three months of 2022, our oil and gas sales for the three months ended March 31, 2022 would have moved up or down $26.3 million for each 10% change in oil prices per Bbl, $4.5 million for each 10% change in NGL prices per Bbl, and $3.9 million for each 10% change in natural gas prices per Mcf.
Due to this volatility, we have historically used, and we may elect to continue to selectively use, commodity derivative instruments (such as collars, swaps and basis swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flows that can emanate from fluctuations in oil and natural gas prices, and thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, but alternatively they partially limit our potential gains from future increases in prices. Our Credit Agreement limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated projected production from proved properties.
The table below summarizes the terms of the derivative contracts we had in place as of March 31, 2022 and additional contracts entered into through April 30, 2022. Refer to Note 6—Derivative Instruments in Item 1 of Part I of this Quarterly Report for open derivative positions as of March 31, 2022.
PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Crude Price
($/Bbl)(1)
Crude oil swaps
April 2022 - June 20221,092,000 12,000 $65.28
July 2022 - September 2022782,000 8,500 65.46
October 2022 - December 2022690,000 7,500 65.63
January 2023 - March 2023225,000 2,500 73.51
April 2023 - June 2023227,500 2,500 73.25
July 2023 - September 202392,000 1,000 72.98
October 2023 - December 202392,000 1,000 72.98
PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Collar Price Ranges
($/Bbl)(2)
Crude oil collars
NYMEX WTIApril 2022 - June 2022227,500 2,500 $63.20-$72.41
July 2022 - September 2022276,000 3,000 75.00-92.46
October 2022 - December 2022276,000 3,000 75.00-92.46
January 2023 - March 2023450,000 5,000 73.00-85.68
April 2023 - June 2023455,000 5,000 73.00-85.68
July 2023 - September 2023276,000 3,000 73.33-85.66
October 2023 - December 2023276,000 3,000 73.33-85.66
ICE BrentApril 2022 - June 202291,000 1,000 $90.00-$105.20
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PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(3)
Crude oil differential basis swapsApril 2022 - June 2022637,000 7,000 $0.34
July 2022 - September 2022552,000 6,000 0.29
October 2022 - December 2022552,000 6,000 0.29
PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(4)
Crude oil roll differential swapsApril 2022 - June 2022910,000 10,000 $0.71
July 2022 - September 2022920,000 10,000 0.71
October 2022 - December 2022920,000 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 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.

PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Gas Price
($/MMBtu)(1)
Natural gas swaps
April 2022 - June 20222,730,000 30,000 $3.24
July 2022 - September 20222,760,000 30,000 3.24
October 2022 - December 20221,540,000 16,739 3.15
PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Differential
($/MMBtu)(2)
Natural gas basis differential swaps
April 2022 - June 20221,820,000 20,000 $(0.45)
July 2022 - September 20221,840,000 20,000 (0.45)
October 2022 - December 20221,840,000 20,000 (0.45)
January 2023 - March 20232,250,000 25,000 (1.11)
April 2023 - June 20232,275,000 25,000 (1.11)
July 2023 - September 20232,300,000 25,000 (1.11)
October 2023 - December 20232,300,000 25,000 (1.11)
PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Collar Price Ranges
($/MMBtu)(3)
Natural gas collars
April 2022 - June 20221,820,000 20,000 $3.50-$3.97
July 2022 - September 20221,840,00020,000 3.50-3.97
October 2022 - December 20222,450,00026,630 3.87-5.06
January 2023 - March 20234,500,00050,000 4.00-7.12
April 2023 - June 20233,640,00040,000 3.56-6.86
July 2023 - September 20233,680,00040,000 3.56-6.86
October 2023 - December 20233,680,00040,000 3.60-7.28
January 2024 - March 20241,820,00020,000 3.25-5.31
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(1)    These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2)    These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas, during each applicable monthly settlement period.
(3)    These natural gas collars are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
Changes in the fair value of derivative contracts from December 31, 2021 to March 31, 2022, are presented below:
(in thousands)Commodity derivative asset (liability)
Net fair value of oil and gas derivative contracts outstanding as of December 31, 2021$(34,910)
Commodity hedge contract settlement payments, net of any receipts42,878 
Cash and non-cash mark-to-market losses on commodity hedge contracts(1)
(129,523)
Net fair value of oil and gas derivative contracts outstanding as of March 31, 2022$(121,555)
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 March 31, 2022 would cause a $45.8 million increase or $45.3 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 March 31, 2022 would cause a $8.4 million increase or $8.2 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 Agreement interest rate is based on a SOFR spread, which exposes us to interest rate risk to the extent we have borrowings outstanding under this credit facility. As of March 31, 2022, we had no borrowings outstanding under the Credit 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 $801.2 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 3—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 March 31, 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 March 31, 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 March 31, 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—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 2021 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2021 Annual Report or our SEC filings.

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Item 6. Exhibits
Exhibit
Number
Description of Exhibit
3.1
3.2
3.3
3.4
3.5
3.6
10.1#
10.2*#
31.1*
31.2*
32.1*
32.2*
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.
44
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
By:/s/ GEORGE S. GLYPHIS
George S. Glyphis
Executive Vice President and Chief Financial Officer
Date:May 5, 2022

45
Exhibit 10.2

CENTENNIAL RESOURCE DEVELOPMENT, INC.
2016 LONG TERM INCENTIVE PLAN

PERFORMANCE RESTRICTED STOCK UNIT GRANT NOTICE

Capitalized terms not specifically defined in this Performance Restricted Stock Unit Grant Notice (the “Grant Notice”) have the meanings given to them in the 2016 Long Term Incentive Plan (as amended and/or restated from time to time, the “Plan”) of Centennial Resource Development, Inc. (the “Company”).

The Company has granted to the participant listed below (“Participant”) the Restricted Stock Units described in this Grant Notice (the “PSUs”), subject to the terms and conditions of the Plan and the Performance Restricted Stock Unit Agreement attached as Exhibit A (the “Agreement”), both of which are incorporated into this Grant Notice by reference.

Participant:[__________]
Grant Date:April 27, 2022
Performance Period:April 1, 2022 through March 31, 2025
Target Number of PSUs:[__________]

By Participant’s signature below, Participant agrees to be bound by the terms of this Grant Notice, the Plan and the Agreement. Participant has reviewed the Plan, this Grant Notice and the Agreement in their entirety, has had an opportunity to obtain the advice of counsel prior to executing this Grant Notice and fully understands all provisions of the Plan, this Grant Notice and the Agreement. Participant hereby agrees to accept as binding, conclusive and final all decisions or interpretations of the Administrator upon any questions arising under the Plan, this Grant Notice or the Agreement.


CENTENNIAL RESOURCE DEVELOPMENT, INC.PARTICIPANT
By:
Name:[Participant Name]
Title:








Exhibit A
PERFORMANCE RESTRICTED STOCK UNIT AGREEMENT

Capitalized terms not specifically defined in this Agreement have the meanings specified in the Grant Notice or, if not defined in the Grant Notice, in the Plan.

ARTICLE I.
GENERAL


1.1     Award of PSUs and Dividend Equivalents.
(a)    The Company has granted the PSUs to Participant effective as of the grant date set forth in the Grant Notice (the “Grant Date”). Each PSU represents the right to receive one Share or, at the option of the Administrator, an amount of cash, in either case, as set forth in this Agreement. Participant will have no right to receive any Shares or cash in respect of this Award until the time (if ever) the PSUs have vested.

(b)    The Company hereby grants to Participant, with respect to each PSU, a Dividend Equivalent for ordinary cash dividends paid to substantially all holders of outstanding Shares with a record date after the Grant Date and prior to the date the applicable PSU is settled, forfeited or otherwise expires. Each Dividend Equivalent entitles Participant to receive the equivalent value of any such ordinary cash dividends paid on a single Share. The Company will establish a separate Dividend Equivalent bookkeeping account (a “Dividend Equivalent Account”) for each Dividend Equivalent and credit the Dividend Equivalent Account (without interest) on the applicable dividend payment date with the amount of any such cash paid.

1.2    Incorporation of Terms of Plan. The PSUs and Dividend Equivalents are subject to the terms and conditions set forth in this Agreement and the Plan, which is incorporated herein by reference. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan will control

1.3    Unsecured Promise. The PSUs and Dividend Equivalents will at all times prior to settlement represent an unsecured Company obligation payable only from the Company’s general assets.

ARTICLE II.
VESTING; FORFEITURE AND SETTLEMENT

2.1    Vesting; Forfeiture.
(a)    The PSUs will be earned based on the Company’s achievement of the performance conditions set forth in Appendix A and, to the extent earned, the PSUs will vest in accordance with the schedule and terms set forth in Section 2.1(b). Any fraction of a PSU that would otherwise be vested will be rounded to the nearest whole PSU. Any PSUs that are not earned in accordance with the performance conditions set forth in Appendix A will immediately and automatically be cancelled and forfeited without consideration as of the date of determination. In the event of Participant’s Termination of Service for any reason, all unearned PSUs will immediately and automatically be cancelled and forfeited, except as otherwise




determined by the Administrator or provided in a binding written agreement between Participant and the Company. Dividend Equivalents (including any Dividend Equivalent Account balance) will vest or be forfeited, as applicable, upon the vesting or forfeiture of the PSU with respect to which the Dividend Equivalent (including the Dividend Equivalent Account) relates.

(b)    The PSUs will be earned, if at all, at a level of between 26.25% and 250% of the Target Number of PSUs specified in the Grant Notice (the “Target Number of PSUs”) based on the Company’s achievement of the performance conditions set forth in Appendix A for the Performance Period set forth in the Grant Notice (the “Performance Period”). When practicable following the completion of the Performance Period, but in no event more than forty-five (45) days thereafter, the Administrator shall determine the extent to which the performance conditions set forth in Appendix A have been satisfied (such date of determination, the “Final Determination Date”). To the extent earned, the PSUs will vest on the Final Determination Date, subject to Participant not incurring a Termination of Service on or prior to the last day of the Performance Period.

2.2    Settlement.

(a)    PSUs and Dividend Equivalents (including any Dividend Equivalent Account balance) will be paid in Shares or cash at the Administrator’s option as soon as administratively practicable after the vesting of the applicable PSU, but in no event more than thirty (30) days after the PSU’s vesting date. Notwithstanding the foregoing, the Company may delay any payment under this Agreement that the Company reasonably determines would violate Applicable Law until the earliest date the Company reasonably determines the making of the payment will not cause such a violation (in accordance with Treasury Regulation Section 1.409A-2(b)(7)(ii)), provided the Company reasonably believes the delay will not result in the imposition of excise taxes under Section 409A.

(b)    If a PSU is paid in cash, the amount of cash paid with respect to each PSU will equal the average Fair Market Value of a Share over the five consecutive trading days ending on the day before the PSU’s vesting date, less applicable withholdings. If a Dividend Equivalent is paid in Shares, the number of Shares paid with respect to the Dividend Equivalent will equal the quotient, rounded down to the nearest whole Share, of the Dividend Equivalent Account balance divided by the average Fair Market Value of a Share over the five consecutive trading days ending on the day before the payment date.

(c)    Notwithstanding anything to the contrary in this Agreement, this Award may only be settled in Shares to the extent Shares are then available for issuance in respect of the Award under the terms of the Plan.

ARTICLE III.
TAXATION AND TAX WITHHOLDING

3.1    Representation. Participant represents to the Company that Participant has reviewed with Participant’s own tax advisors the tax consequences of this Award and the transactions contemplated by the Grant Notice and this Agreement. Participant is relying solely on such advisors and not on any statements or representations of the Company or any of its agents.
2




3.2    Tax Withholding.
(a)    The Company has the right and option, but not the obligation, to treat Participant’s failure to provide timely payment in accordance with the Plan of any withholding tax arising in connection with the PSUs or Dividend Equivalents as Participant’s election to satisfy all or any portion of the withholding tax by requesting the Company retain Shares otherwise issuable under the Award.

(b)    Participant acknowledges that Participant is ultimately liable and responsible for all taxes owed in connection with the PSUs and the Dividend Equivalents, regardless of any action the Company or any Subsidiary takes with respect to any tax withholding obligations that arise in connection with the PSUs or Dividend Equivalents. Neither the Company nor any Subsidiary makes any representation or undertaking regarding the treatment of any tax withholding in connection with the awarding, vesting or payment of the PSUs or the Dividend Equivalents or the subsequent sale of Shares. The Company and the Subsidiaries do not commit and are under no obligation to structure the PSUs or Dividend Equivalents to reduce or eliminate Participant’s tax liability.

ARTICLE IV.
OTHER PROVISIONS

4.1    Adjustments.    Participant acknowledges that the PSUs, the Shares subject to the PSUs and the Dividend Equivalents are subject to adjustment, modification and termination in certain events as provided in this Agreement and the Plan.

4.2    Notices. Any notice to be given under the terms of this Agreement to the Company must be in writing and addressed to the Company in care of the Company’s Secretary at the Company’s principal office or the Secretary’s then-current email address or facsimile number. Any notice to be given under the terms of this Agreement to Participant must be in writing and addressed to Participant at Participant’s last known mailing address, email address or facsimile number in the Company’s personnel files. By a notice given pursuant to this Section, either party may designate a different address for notices to be given to that party. Any notice will be deemed duly given when actually received, when sent by email, when sent by certified mail (return receipt requested) and deposited with postage prepaid in a post office or branch post office regularly maintained by the United States Postal Service, when delivered by a nationally recognized express shipping company or upon receipt of a facsimile transmission confirmation.

4.3    Titles. Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement.

4.4    Conformity to Securities Laws. Participant acknowledges that the Plan, the Grant Notice and this Agreement are intended to conform to the extent necessary with all Applicable Laws and, to the extent Applicable Laws permit, will be deemed amended as necessary to conform to Applicable Laws.

4.5    Successors and Assigns. The Company may assign any of its rights under this Agreement to single or multiple assignees, and this Agreement will inure to the benefit of the
3



successors and assigns of the Company. Subject to the restrictions on transfer set forth in the Plan, this Agreement will be binding upon and inure to the benefit of the heirs, legatees, legal representatives, successors and assigns of the parties hereto.

4.6    Limitations Applicable to Section 16 Persons. Notwithstanding any other provision of the Plan or this Agreement, if Participant is subject to Section 16 of the Exchange Act, the Plan, the Grant Notice, this Agreement, the PSUs and the Dividend Equivalents will be subject to any additional limitations set forth in any applicable exemptive rule under Section 16 of the Exchange Act (including any amendment to Rule 16b-3) that are requirements for the application of such exemptive rule. To the extent Applicable Laws permit, this Agreement will be deemed amended as necessary to conform to such applicable exemptive rule.

4.7    Entire Agreement. The Plan, the Grant Notice and this Agreement (including any exhibit hereto) constitute the entire agreement of the parties and supersede in their entirety all prior undertakings and agreements of the Company and Participant with respect to the subject matter hereof.

4.8    Agreement Severable. In the event that any provision of the Grant Notice or this Agreement is held illegal or invalid, the provision will be severable from, and the illegality or invalidity of the provision will not be construed to have any effect on, the remaining provisions of the Grant Notice or this Agreement.

4.9    Limitation on Participant’s Rights. Participation in the Plan confers no rights or interests other than as herein provided. This Agreement creates only a contractual obligation on the part of the Company as to amounts payable and may not be construed as creating a trust. Neither the Plan nor any underlying program, in and of itself, has any assets. Participant will have only the rights of a general unsecured creditor of the Company with respect to amounts credited and benefits payable, if any, with respect to the PSUs and Dividend Equivalents, and rights no greater than the right to receive cash or the Shares as a general unsecured creditor with respect to the PSUs and Dividend Equivalents, as and when settled pursuant to the terms of this Agreement.

4.10    Not a Contract of Employment. Nothing in the Plan, the Grant Notice or this Agreement confers upon Participant any right to continue in the employ or service of the Company or any Subsidiary or interferes with or restricts in any way the rights of the Company and its Subsidiaries, which rights are hereby expressly reserved, to discharge or terminate the services of Participant at any time for any reason whatsoever, with or without Cause, except to the extent expressly provided otherwise in a written agreement between the Company or a Subsidiary and Participant.

4.11    Counterparts. The Grant Notice may be executed in one or more counterparts, including by way of any electronic signature, subject to Applicable Law, each of which will be deemed an original and all of which together will constitute one instrument.

* * * * *



4


Appendix A

Performance Goals

The performance measures for the PSU award are (a) the Company’s total shareholder return (“TSR”) compared to the TSR of a group of peer companies and one exchange-traded index fund over the Performance Period and (b) the Company’s absolute annualized TSR over the Performance Period. TSR combines share price appreciation and dividends paid to show the total return to the shareholder.

TSR will be (a) (1) the sum of the Company’s ending stock price plus dividends with a record date during the Performance Period minus (2) the Company’s beginning stock price, divided by (b) the Company’s beginning stock price. Both the beginning and ending stock prices will be calculated using the average closing price during the last 20 trading days prior to and including the calculation date. This calculation is used instead of the actual closing price on the given date to smooth volatility in the stock price and avoid single-day fluctuations.

Peer Group

The following 12 companies and one exchange-traded index fund are included in the Company’s peer group for purposes of this Award:

Callon Petroleum Company
Oasis Petroleum Inc.
Civitas Resources, Inc.
PDC Energy, Inc.
Earthstone Energy, Inc.
Ranger Oil Corporation
HighPeak Energy, Inc.
SM Energy Company
Laredo Petroleum, Inc.
SPDR S&P Oil & Gas Exploration & Production ETF (XOP)
Magnolia Oil & Gas Corporation
Whiting Petroleum
Matador Resources Company

Should a peer company cease to exist as a separate publicly traded company during the Performance Period due to bankruptcy, it will nonetheless remain as a member of the Company’s peer group for purposes of the payout calculation described below and the Company shall be ranked higher than such peer company for purposes of the payout calculation. Should a peer company cease to exist as a separate publicly traded company during the Performance Period due to a merger, acquisition or other similar transaction, or should shares of the SPDR S&P Oil & Gas Exploration & Production ETF cease to be publicly traded during the Performance Period, it will be automatically removed from the peer group list and the number of PSUs earned will be determined based on the Company’s percentile rank among the resulting peer group.

Payout Calculation

At the end of the Performance Period, the number of PSUs earned will be equal to (a) the Target Number of PSUs multiplied by (b) the Relative TSR Multiplier (defined below) multiplied by (c) the Absolute TSR Multiplier (defined below). The Relative TSR Multiplier and the Absolute TSR Multiplier are both expressed as percentages and, after both multipliers have been applied,
A-1



the number of PSUs earned, if at all, will be at a level between 26.25% and 250% of the Target Number of PSUs.

Relative TSR Multiplier

The Relative TSR Multiplier is determined based on the Company’s TSR relative to the Company’s peer group over the Performance Period. The Company’s TSR is ranked among the peers and the percentile rank is calculated, based on the Company’s position in the ranking, as the percentage of members of the peer group (including the Company and as the peer group is constituted on the final day of the Performance Period) with a ranking that is greater than or equal to the Company’s ranking (i.e., with a TSR that is less than or equal to the Company’s TSR). The Relative TSR Multiplier will be determined based on the Company’s TSR Percentile Ranking, with linear interpolation between any specified TSR Percentile Ranking set forth in the table below; provided, however, that the Relative TSR Multiplier shall equal 0% if the Company’s TSR Percentile Ranking is below 25%.

TSR Percentile Rankin
Relative TSR
Multiplier
100%
200%
75%
150%
50%
100%
25%
35%
0%
0%

Absolute TSR Multiplier

The Absolute TSR Multiplier is determined based on the Company’s absolute annualized TSR over the Performance Period in accordance with the table below.

Absolute
Annualized TSR
Absolute TSR
Multiplier
Below 0%
75%
Between 0% and 15%
100%
Above 15%
125%

Adjustments for Extraordinary Events

Notwithstanding the foregoing, if the Administrator determines that due to a reduction in the size of the peer group or other unusual, extraordinary or nonrecurring transactions or events materially affecting the Award, an adjustment in the peer group, the payment schedule and/or other terms of the Award is necessary or appropriate to avoid the dilution or enlargement of the benefits or potential benefits intended to be made available under the Award, the Administrator may adjust the peer group (including by removing constituent companies, substituting new constituent companies for existing constituent companies or selecting new constituent companies to replace withdrawn constituent companies), the payment schedule and/or such other terms of the Award in such a manner as the Administrator determines in good faith to be equitable to
A-2



reflect such transactions or events. As used in the prior sentence, “constituent companies” includes indices such as the SPDR S&P Oil & Gas Exploration & Production ETF (XOP).

* * * * *
A-3

EXHIBIT 31.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO RULES 13a-14(a) AND 15d-14(a)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Sean R. Smith, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q (this “report”) of Centennial Resource Development, Inc. (the “registrant”);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: May 5, 2022
CENTENNIAL RESOURCE DEVELOPMENT, INC.
By:/s/ SEAN R. SMITH
Sean R. Smith
Chief Executive Officer (Principal Executive Officer)


EXHIBIT 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO RULES 13a-14(a) AND 15d-14(a)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, George S. Glyphis, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q (this “report”) of Centennial Resource Development, Inc. (the “registrant”);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: May 5, 2022
CENTENNIAL RESOURCE DEVELOPMENT, INC.
By:/s/ GEORGE S. GLYPHIS
George S. Glyphis
Executive Vice President and Chief Financial Officer (Principal Financial Officer)


EXHIBIT 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the quarter ended March 31, 2022 of Centennial Resource Development, Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Sean R. Smith, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date: May 5, 2022
CENTENNIAL RESOURCE DEVELOPMENT, INC.
By:/s/ SEAN R. SMITH
Sean R. Smith
Chief Executive Officer (Principal Executive Officer)





EXHIBIT 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the quarter ended March 31, 2022 of Centennial Resource Development, Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, George S. Glyphis, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date: May 5, 2022
CENTENNIAL RESOURCE DEVELOPMENT, INC.
By:/s/ GEORGE S. GLYPHIS
George S. Glyphis
Executive Vice President and Chief Financial Officer (Principal Financial Officer)