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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 June 30, 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)
Delaware 47-5381253
(State of Incorporation) (I.R.S. Employer Identification No.)
1001 Seventeenth Street, Suite 1800
Denver, Colorado 80202
(Registrant’s telephone number, including area code): (720) 499-1400
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s) Name of each exchange on which registered
Common Stock, par value $0.0001 per share CDEV The NASDAQ Stock Market LLC
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer   Accelerated filer   Non-accelerated filer   Smaller reporting company  Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No
As of July 31, 2022, there were 285,059,255 shares of Common Stock, par value $0.0001 per share outstanding.



TABLE OF CONTENTS
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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 ability to identify, complete and effectively integrate acquisitions of properties or businesses, including our pending merger with Colgate Energy Partners III, LLC;
our drilling prospects, inventories, projects and programs; 
our financial strategy, leverage, liquidity and capital required for our development program; 
our realized oil, natural gas and NGL prices; 
the timing and amount of our future production of oil, natural gas and NGLs; 
our hedging strategy and results; 
our competition and government regulations; 
our ability to obtain permits and governmental approvals; 
our pending legal or environmental matters; 
the marketing and transportation of our oil, natural gas and NGLs; 
our leasehold or business acquisitions; 
cost of developing or operating our properties;
our anticipated rate of return;
general economic conditions; 
weather conditions in the areas where we operate;
credit markets; 
uncertainty regarding our future operating results; and 
our plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.
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We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in “Item 1A. Risk Factors” in our 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)
June 30, 2022 December 31, 2021
ASSETS
Current assets
Cash and cash equivalents
$ 201,092  $ 9,380 
Accounts receivable, net
141,598  71,295 
Prepaid and other current assets
7,189  5,860 
Total current assets
349,879  86,535 
Property and Equipment
Oil and natural gas properties, successful efforts method
Unproved properties
984,264  1,040,386
Proved properties
4,929,108  4,623,726
Accumulated depreciation, depletion and amortization
(2,140,982) (1,989,489)
Total oil and natural gas properties, net
3,772,390  3,674,623
Other property and equipment, net 13,167  11,197
Total property and equipment, net
3,785,557  3,685,820 
Noncurrent assets
Operating lease right-of-use assets
54,934  16,385 
Other noncurrent assets
33,660  15,854
TOTAL ASSETS
$ 4,224,030  $ 3,804,594 
LIABILITIES AND EQUITY
Current liabilities
  Accounts payable and accrued expenses
$ 208,222  $ 130,256 
Operating lease liabilities 21,124  1,413 
Derivative instruments 83,541  35,150 
Other current liabilities
3,214  1,080 
Total current liabilities
316,101  167,899
 Noncurrent liabilities
Long-term debt, net
801,849  825,565 
Asset retirement obligations
18,151  17,240 
Deferred income taxes
50,293  2,589 
Operating lease liabilities 35,724  16,002 
Other noncurrent liabilities
32,344  24,579 
Total liabilities
1,254,462  1,053,874
Commitments and contingencies (Note 12)
Shareholders’ equity
Common stock, $0.0001 par value, 620,000,000 shares authorized; 297,060,327 shares issued and 284,992,650 shares outstanding at June 30, 2022 and 294,260,623 shares issued and 284,696,972 shares outstanding at December 31, 2021
30  29 
Additional paid-in capital 3,024,236  3,013,017 
Retained earnings (accumulated deficit) (54,698) (262,326)
Total Shareholders' equity 2,969,568  2,750,720 
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 4,224,030  $ 3,804,594 
The accompanying notes are an integral part of these unaudited consolidated financial statements.
7

CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 2022 2021
 Operating revenues
Oil and gas sales $ 472,654  $ 232,577  $ 819,931  $ 424,968 
Operating expenses
Lease operating expenses 28,900  22,976  57,634  48,837 
Severance and ad valorem taxes 34,695  15,784  59,746  28,367 
Gathering, processing and transportation expenses 25,756  19,494  47,647  40,119 
Depreciation, depletion and amortization 82,117  73,429  153,126  137,212 
General and administrative expenses 9,947  28,807  40,550  54,063 
Merger and integration expense 5,685  —  5,685  — 
Impairment and abandonment expense 506  9,199  3,133  18,399 
Exploration and other expenses 1,954  1,764  4,261  2,859 
Total operating expenses 189,560  171,453  371,782  329,856 
Net gain (loss) on sale of long-lived assets (1,406) (8) (1,324) 36 
Proceeds from terminated sale of assets —  5,983  —  5,983 
Income (loss) from operations 281,688  67,099  446,825  101,131 
Other income (expense)
Interest expense (14,326) (15,182) (27,480) (32,667)
Gain (loss) on extinguishment of debt —  (22,156) —  (22,156)
Net gain (loss) on derivative instruments (34,134) (54,959) (163,657) (106,158)
Other income (expense) 85  143  203  150 
Total other income (expense)
(48,375) (92,154) (190,934) (160,831)
Income (loss) before income taxes 233,313  (25,055) 255,891  (59,700)
Income tax (expense) benefit (41,487) —  (48,263) — 
Net income (loss) $ 191,826  $ (25,055) $ 207,628  $ (59,700)
Income (loss) per share of Common Stock:
Basic $ 0.67  $ (0.09) $ 0.73  $ (0.21)
Diluted $ 0.60  $ (0.09) $ 0.66  $ (0.21)
The accompanying notes are an integral part of these unaudited consolidated financial statements.

8

CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
Six Months Ended June 30,
2022

2021
Cash flows from operating activities:
Net income (loss) $ 207,628  $ (59,700)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization
153,126  137,212 
Stock-based compensation expense - equity awards
12,202  9,066 
Stock-based compensation expense - liability awards 5,127  25,074 
Impairment and abandonment expense
3,133  18,399 
Deferred tax expense (benefit)
47,663  — 
Net (gain) loss on sale of long-lived assets 1,324  (36)
Non-cash portion of derivative (gain) loss 47,131  45,759 
Amortization of debt issuance costs and debt discount 4,226  2,886 
(Gain) loss on extinguishment of debt —  22,156 
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable (62,751) (33,483)
(Increase) decrease in prepaid and other assets (6,201) (9)
Increase (decrease) in accounts payable and other liabilities 42,491  12,301 
Net cash provided by operating activities 455,099  179,625 
Cash flows from investing activities:
Acquisition of oil and natural gas properties
(2,592) (638)
Drilling and development capital expenditures
(224,011) (126,665)
Purchases of other property and equipment
(2,863) (471)
Proceeds from sales of oil and natural gas properties
863  698 
Net cash used in investing activities (228,603) (127,076)
Cash flows from financing activities:
Proceeds from borrowings under revolving credit facility
170,000  320,000 
Repayment of borrowings under revolving credit facility
(195,000) (395,000)
Proceeds from issuance of senior notes —  170,000 
Debt issuance costs
(8,533) (6,421)
Premiums paid on capped call transactions —  (14,688)
Redemption of senior secured notes —  (127,073)
Proceeds from exercise of stock options 15 
Restricted stock used for tax withholdings (1,259) (477)
Net cash used in financing activities (34,784) (53,644)
Net increase (decrease) in cash, cash equivalents and restricted cash
191,712  (1,095)
Cash, cash equivalents and restricted cash, beginning of period
9,935  8,339 
Cash, cash equivalents and restricted cash, end of period
$ 201,647  $ 7,244 
The accompanying notes are an integral part of these unaudited consolidated financial statements.
9

CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (continued)
(in thousands)
Six Months Ended June 30,
2022

2021
Supplemental cash flow information
Cash paid for interest
$ 24,276  $ 30,124 
Cash paid for income taxes 600  — 
Supplemental non-cash activity
Accrued capital expenditures included in accounts payable and accrued expenses
$ 63,486  $ 53,096 
Asset retirement obligations incurred, including revisions to estimates
389  66 
Reconciliation of cash, cash equivalents and restricted cash presented on the consolidated statements of cash flows for the periods presented:
Six Months Ended June 30,
2022 2021
Cash and cash equivalents
$ 201,092  $ 4,702 
Restricted cash(1)
555  2,542 
Total cash, cash equivalents and restricted cash
$ 201,647  $ 7,244 
(1)    Included in Prepaid and other current assets in the consolidated balance sheet as of June 30, 2022.

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

10

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


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

Balance at December 31, 2020 290,646  $ 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 Plan 276  —  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, 2021 290,793  29  2,994,020  (435,146) 2,558,903 
Restricted stock forfeited (7) —  —  —  — 
Stock option exercises 15  —  15  —  15 
Stock-based compensation - equity awards —  —  4,481  —  4,481 
Net income (loss) —  —  —  (25,055) (25,055)
Balance at June 30, 2021 290,801  29  $ 2,998,516  $ (460,201) $ 2,538,344 

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

11




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. During the second quarter of 2022, the Company extended two drilling rig contracts each for a two-year period. A lease right-of-use (ROU) asset and related liability have been recorded based on the present value of the future lease payments over the lease term of the drilling rigs. As of June 30, 2022, $19.0 million was recorded to current operating lease liability and $21.6 million was recorded to noncurrent operating lease liability related to these rigs. There have been no other significant changes in operating leases during the six months ended June 30, 2022. Refer to Note 15—Leases footnote in the notes to the consolidated financial statements in Item 8 of the Company’s 2021 Annual Report.
12

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Income Taxes
Income tax expense recognized during interim periods is based on applying an estimated annual effective income tax rate to the Company’s year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various state jurisdictions, permanent and temporary differences and the likelihood of recovering deferred tax assets generated. The accounting estimates used to compute the provision for income taxes may change as new events occur, additional information becomes known or as the tax environment changes.
Note 2—Business Combination
Pending Merger with Colgate
On May 19, 2022, the Company entered into a Business Combination Agreement (the “Business Combination Agreement”) with CRP, Colgate Energy Partners III, LLC (“Colgate”), and Colgate Energy Partners III MidCo, LLC (the “Colgate Unitholder”) which provides for the combination of CRP and Colgate in a merger of equals transaction (the “Merger”), with CRP surviving the Merger (the “Surviving Company”) as a subsidiary of Centennial.
Colgate is an independent oil and gas company focused on the acquisition, development, exploration and production of oil and natural gas properties in the Delaware Basin. Colgate owns approximately 105,000 net leasehold acres and 25,000 net royalty acres in Reeves and Ward counties in Texas and Eddy County in New Mexico.
At the effective time of the Merger, all membership interests in CRP issued and outstanding will be converted into units in the Surviving Company (“Surviving Company Units”) equal to the number of shares of Centennial’s Class A common stock (the “Common Stock”) that are outstanding at such time, and all of the Colgate Unitholder’s membership interest in Colgate will be exchanged for 269,300,000 shares of Class C common stock (with underlying Surviving Company Units) and $525 million in cash. The shares of Class C Common Stock to be issued to the Colgate Unitholders pursuant to the Business Combination Agreement will represent a noncontrolling interest in the Surviving Company.
The transaction has been unanimously approved by the Boards of Directors of both companies. The Company has filed its definitive proxy statement with the SEC and the shareholder meeting is scheduled for August 29, 2022, where the Merger will be voted on by the Company’s shareholders. The Merger is expected to close shortly after the shareholder meeting subject to customary closing conditions, including, among others, receipt of the required approvals from the Company’s shareholders.
Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
(in thousands)
June 30, 2022 December 31, 2021
Accrued oil and gas sales receivable, net
$ 114,168  $ 57,287 
Joint interest billings, net
26,051  12,449 
Other
1,379  1,559 
Accounts receivable, net
$ 141,598  $ 71,295 
Accounts payable and accrued expenses are comprised of the following:
(in thousands)
June 30, 2022 December 31, 2021
Accounts payable
$ 31,134  $ 9,736 
Accrued capital expenditures
49,791  24,377
Revenues payable
60,541  40,438
Accrued employee compensation and benefits
9,038  17,218
Accrued interest
15,423  15,259
Accrued derivative settlements payable
21,168  8,591
Accrued expenses and other
21,127  14,637
Accounts payable and accrued expenses
$ 208,222  $ 130,256 
13

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 4—Long-Term Debt
The following table provides information about the Company’s long-term debt as of the dates indicated:
(in thousands)
June 30, 2022 December 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
(12,152) (13,279)
Unamortized debt discount
(1,798) (1,955)
Senior Notes, net 801,849  800,565 
Total long-term debt, net
$ 801,849  $ 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 June 30, 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 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 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 CRP 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
14

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(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 June 30, 2022. In July 2022 in connection with the pending Merger, CRP amended its Credit Agreement; refer to Note 14—Subsequent Events for additional information.
Convertible Senior Notes
On March 19, 2021, CRP issued $150.0 million in aggregate principal amount of 3.25% senior unsecured convertible notes due 2028 (the “Convertible Senior Notes”). On March 26, 2021, CRP issued an additional $20.0 million of Convertible Senior Notes pursuant to the exercise of the underwriters’ over-allotment option to purchase additional Convertible Senior Notes. These issuances resulted in aggregate net proceeds to CRP of $163.6 million, after deducting debt issuance costs of $6.4 million. Interest is payable on the Convertible Senior Notes semi-annually in arrears on each April 1 and October 1, commencing on October 1, 2021.
The Convertible Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP’s current subsidiaries.
The Convertible Senior Notes will mature on April 1, 2028 unless earlier repurchased, redeemed or converted. Before January 3, 2028, noteholders have the right to convert their Convertible Senior Notes (i) upon the occurrence of certain events, (ii) if the Company’s share price exceeds 130% of the conversion price for any 20 trading days during the last 30 consecutive trading days of a calendar quarter, after June 30, 2021, or (iii) if the trading price per $1,000 principal amount of the notes is less than 98% of the Company’s share price multiplied by the conversion rate, for a 10 consecutive trading day period. In addition, after January 2, 2028, noteholders may convert their Convertible Senior Notes at any time at their election through the second scheduled trading day immediately before the April 1, 2028 maturity date.
CRP can settle conversions by paying or delivering, as applicable, cash, shares of Common Stock, or a combination of cash and shares of Common Stock, at CRP’s election. The initial conversion rate is 159.2610 shares of Common Stock per $1,000 principal amount of Convertible Senior Notes, which represents an initial conversion price of approximately $6.28 per share of Common Stock. The conversion rate and conversion price are subject to customary adjustments upon the occurrence of certain events (as defined in the indenture) which, in certain circumstances, will increase the conversion rate for a specified period of time. In the context of this issuance, we refer to the notes as convertible in accordance with ASC 470 - Debt. However, per the terms of the Convertible Senior Notes’ indenture, the Convertible Senior Notes were issued by CRP and are exchangeable into shares of Centennial Resource Development, Inc.’s Common Stock.
CRP has the option to redeem, in whole or in part, all of the Convertible Senior Notes at any time on or after April 7, 2025, at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest to the date of redemption, but only if the last reported sale price per share of Common Stock exceeds 130% of the conversion price (i) for any 20 trading days during the 30 consecutive trading days ending on the day immediately before the date CRP sends the related redemption notice; and (ii) also on the trading day immediately before the date CRP sends such notice.
If certain corporate events occur, including certain business combination transactions involving the Company or CRP or a stock de-listing with respect to the Common Stock, noteholders may require CRP to repurchase their Convertible Senior Notes at a cash repurchase price equal to the principal amount of the Convertible Senior Notes to be repurchased, plus accrued and unpaid interest to the repurchase date.
Upon an Event of Default (as defined in the indenture governing the Convertible Senior Notes), the trustee or the holders of at least 25% of the aggregate principal amount of then outstanding Convertible Senior Notes may declare the Convertible Senior Notes immediately due and payable. In addition, a default resulting from certain events of bankruptcy or insolvency with respect to the Company, CRP or any of the subsidiary guarantors will automatically cause all outstanding Convertible Senior Notes to become due and payable.
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 June 30, 2022, the net liability recorded related to the Convertible Senior Notes was $164.6 million.
15

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Capped Called Transactions
In connection with the issuance of the Convertible Senior Notes in March 2021, CRP entered into privately negotiated capped call spread transactions with option counterparties (the “Capped Call Transactions”). The Capped Call Transactions cover the aggregate number of shares of Common Stock that initially underlie the Convertible Senior Notes and are expected to (i) generally reduce potential dilution to the Common Stock upon a conversion of the Convertible Senior Notes, and/or (ii) offset any cash payments CRP is required to make in excess of the principal amount of the Convertible Senior Notes, subject to a cap. The Capped Call Transactions have an initial strike price of $6.28 per share of Common Stock and an initial capped price of $8.4525 per share of Common Stock, each of which are subject to certain customary adjustments upon the occurrence of certain corporate events, as defined in the capped call agreements.
The cost of the Capped Call Transactions was $14.7 million, which was funded from proceeds from the Convertible Senior Note issuance. The cost to purchase the Capped Call Transactions was recorded to additional paid-in capital in the consolidated balances sheets and will not be subject to remeasurement each reporting period.
Senior Unsecured Notes
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 June 30, 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
16

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with these covenants as of June 30, 2022 and through the filing of this Quarterly Report.
Upon an Event of Default (as defined in the indentures governing the Senior Unsecured Notes), the trustee or the holders of at least 25% of the aggregate principal amount of then outstanding Senior Unsecured Notes may declare the Senior Unsecured Notes immediately due and payable. In addition, a default resulting from certain events of bankruptcy or insolvency with respect to CRP, any restricted subsidiary of CRP that is a significant subsidiary, or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary, will automatically cause all outstanding Senior Unsecured Notes to become due and payable.
Note 5—Asset Retirement Obligations
The following table summarizes changes in the Company’s asset retirement obligations (“ARO”) associated with its working interests in oil and gas properties for the six months ended June 30, 2022:
(in thousands)
Asset retirement obligations, beginning of period
$ 17,240 
Liabilities incurred
481 
Liabilities divested and settled
(11)
Accretion expense
533 
Revisions to estimated cash flows
(92)
Asset retirement obligations, end of period
$ 18,151 
ARO reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. Inherent in the fair value calculation of ARO are numerous estimates and assumptions, including plug and abandonment settlement amounts, inflation factors, credit adjusted discount rates and timing of settlement. To the extent future revisions to these assumptions impact the value of the existing ARO liabilities, a corresponding offsetting adjustment is made to the oil and gas property balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability with an offsetting charge to accretion expense, which is included within depreciation, depletion and amortization.
Note 6—Stock-Based Compensation
On April 27, 2022, the stockholders of the Company approved the second amended and restated Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the “LTIP”), which, among other things, increased the number of shares of Common Stock authorized for issuance to employees and directors from 24,750,000 shares to 44,250,000 shares. The LTIP provides for grants of restricted stock, stock options (including incentive stock options and nonqualified stock options), restricted stock units (including performance stock units), stock appreciation rights and other stock or cash-based awards.
Stock-based compensation expense is recognized within both General and administrative expenses and Exploration and other expenses in the consolidated statements of operations. The Company accounts for forfeitures of awards granted under the LTIP as they occur in determining compensation expense.
17

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table summarizes stock-based compensation expense recognized for the periods presented:
Three Months Ended June 30, Six Months Ended June 30,
(in thousands) 2022 2021 2022 2021
Equity Awards
Restricted stock $ 4,481  $ 3,536  $ 7,920  $ 7,142 
Stock option awards 26  234  57  505 
Performance stock units 2,079  646  4,082  1,285 
Other stock-based compensation expense(1)
71  65  143  134 
Total stock-based compensation - equity awards 6,657  4,481  12,202  9,066 
Liability Awards
Restricted stock units —  4,647  —  7,955 
Performance stock units (8,593) 10,013  5,127  17,119 
Total stock-based compensation - liability awards (8,593) 14,660  5,127  25,074 
Total stock-based compensation expense $ (1,936) $ 19,141  $ 17,329  $ 34,140 
(1)     Includes expenses related to the Company’s Employee Stock Purchase Plan (the “ESPP”). In May 2019, an aggregate of 2,000,000 shares were authorized by stockholders for issuance under the ESPP, which became effective on July 1, 2019.
Equity Awards
The Company has restricted stock, stock options and performance stock units (“PSUs”) outstanding that were granted under the LTIP as discussed below. Each award has service-based and, in the case of the PSUs, market-based vesting requirements, and are expected to be settled in shares of Common Stock upon vesting. As a result, these awards are classified as equity-based awards in accordance with ASC Topic 718, Compensation-Stock Compensation (“ASC 718”).
Restricted Stock
The following table provides information about restricted stock activity during the six months ended June 30, 2022:
Restricted Stock Weighted Average Fair Value
Unvested balance as of December 31, 2021 10,143,687  $ 2.85 
Granted 2,409,749  7.90 
Vested (387,929) 5.03 
Forfeited (97,829) 5.40 
Unvested balance as of June 30, 2022 12,067,678  3.76 
The Company grants service-based restricted stock to executive officers and employees, which vest ratably over a three-year service period, and to directors, which vest over a one-year service period. Compensation cost for these service-based restricted stock is based on the closing market price of the Company’s Common Stock on the grant date, and such costs are recognized ratably over the applicable vesting period. The total fair value of restricted stock that vested during the six months ended June 30, 2022 and 2021 was $2.0 million and $2.7 million, respectively. Unrecognized compensation cost related to restricted shares that were unvested as of June 30, 2022 was $32.4 million, which the Company expects to recognize over a weighted average period of 2.5 years.
Stock Options
Stock options that have been granted under the LTIP expire ten years from the grant date and 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.
18

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table provides information about stock option awards outstanding during the six months ended June 30, 2022:
Options Weighted Average Exercise Price Weighted Average Remaining Term
(in years)
Aggregate Intrinsic Value
(in thousands)
Outstanding as of December 31, 2021 2,212,798  $ 15.31 
Granted —  — 
Exercised (4,000) 1.92  $ 24 
Forfeited (2,500) 7.58 
Expired (60,832) 14.69 
Outstanding as of June 30, 2022 2,145,466  15.36  4.9 $ 276 
Exercisable as of June 30, 2022 2,094,791  15.63  4.9 $ 165 
The total fair value of stock options that vested during the six months ended June 30, 2022 and 2021 was $0.2 million and $0.5 million, respectively. The intrinsic value of the stock options exercised was minimal for the six months ended June 30, 2022 and $0.1 million for the six months ended June 30, 2021. As of June 30, 2022, there was less than $0.1 million of unrecognized compensation cost related to unvested stock options, which the Company expects to recognize on a pro-rata basis over a weighted-average period of 0.6 years.
Performance Stock Units
The Company grants performance stock units (“PSU”) to certain executive officers that are subject to market-based vesting criteria as well as a three-year service period. Vesting at the end of the three-year service period is subject to the condition that the Company’s stock price increases by a greater percentage, or decreases by a lesser percentage, than the average percentage increase or decrease, respectively, of the stock prices of a peer group of companies. These market-based conditions must be met in order for the stock awards to vest, and it is therefore possible that no shares could ultimately vest. However, the Company recognizes compensation expense for the 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 six months ended June 30, 2022 and the year ended December 31, 2021 there were 0.7 million and 1.1 million shares, respectively, of performance stock units granted that can be settled in either Common Stock or cash upon vesting at the Company’s discretion. The Company currently intends to settle these performance stock units in Common Stock and has sufficient shares available under the LTIP to settle the units in Common Stock at the potential future vesting dates. Accordingly, these units have been treated as equity-based awards and a grant date was established on April 27, 2022, which represents the date the 2022 awards were approved and the date sufficient shares become available under the LTIP to settle 2021 awards in Common Stock. As a result, these PSU awards’ fair value was determined as of the grant date and remeasurement of such value will not be required.
The fair value was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company’s Common Stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period.
The following table summarizes the key assumptions and related information used to determine the fair value of performance stock units:
2021 Awards 2022 Awards
Weighted average fair value per share $12.79 $13.81
Number of simulations 10,000,000 10,000,000
Expected implied stock volatility 99.5% 96.3%
Dividend yield —% —%
Risk-free interest rate 2.3% 2.7%
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table provides information about performance stock units outstanding during the six months ended June 30, 2022:
Awards Weighted Average Fair Value
Unvested balance as of December 31, 2021 1,580,980  $ 8.54 
Granted 733,330  13.81 
Vested —  — 
Cancelled —  — 
Forfeited —  — 
Unvested balance as of June 30, 2022 2,314,310  11.83 
As of June 30, 2022, there was $19.1 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 2.4 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 June 30, 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 June 30, 2022, there was $15.2 million of unrecognized compensation cost that represents the unvested portion of the fair value of the PSUs at June 30, 2022 and will be recognized over a weighted average period of 1.0 years.
20

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Liability Awards Fair Value
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 June 30, 2022:
Performance stock units
Number of simulations 10,000,000
Expected implied stock volatility 73.7%
Dividend yield —%
Risk-free interest rate 2.8%
Note 7—Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations and may use derivative instruments to manage its exposure to commodity price risk from time to time.
Commodity Derivative Contracts
Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. The Company may periodically use derivative instruments, such as swaps, costless collars and basis swaps, to mitigate its exposure to declines in commodity prices and to the corresponding negative impacts such declines can have on its cash flows from operations, returns on capital and other financial results. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. The Company does not enter into derivative contracts for speculative or trading purposes.
Commodity Swap and Collar Contracts. The Company may use commodity derivative instruments known as fixed price swaps to realize a known price for a specific volume of production, basis swaps to hedge the difference between the index price and a local or future index price, or costless collars to establish fixed price floors and ceilings. All transactions are settled in cash with one party paying the other for the resulting difference in price multiplied by the contract volume.
The following table summarizes the approximate volumes and average contract prices of derivative contracts the Company had in place as of June 30, 2022:
Period Volume (Bbls) Volume
(Bbls/d)
Wtd. Avg. Crude Price
($/Bbl)(1)
Crude oil swaps
July 2022 - September 2022 782,000  8,500  $65.46
October 2022 - December 2022 690,000  7,500  65.63
January 2023 - March 2023 225,000  2,500  73.51
April 2023 - June 2023 227,500  2,500  73.25
July 2023 - September 2023 92,000  1,000  72.98
October 2023 - December 2023 92,000  1,000  72.98
Period Volume (Bbls) Volume
(Bbls/d)
Wtd. Avg. Collar Price Ranges
($/Bbl)(2)
Crude oil collars July 2022 - September 2022 460,000  5,000  $78.00 - $107.13
October 2022 - December 2022 644,000  7,000  80.00 - 104.17
January 2023 - March 2023 810,000  9,000  75.56 - 91.15
April 2023 - June 2023 819,000  9,000  75.56 - 91.15
July 2023 - September 2023 644,000  7,000  76.43 - 92.70
October 2023 - December 2023 644,000  7,000  76.43 - 92.70
21

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


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

Period Volume (Bbls) Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(4)
Crude oil roll differential swaps
July 2022 - September 2022 920,000  10,000  $0.71
October 2022 - December 2022 920,000  10,000  0.71
(1)    These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2)    These crude oil collars are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3)    These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
(4)    These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.

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

Period Volume (MMBtu) Volume (MMBtu/d)
Wtd. Avg. Differential
($/MMBtu)(2)
Natural gas basis differential swaps
July 2022 - September 2022 1,840,000  20,000  $(0.45)
October 2022 - December 2022 1,840,000  20,000  (0.45)
January 2023 - March 2023 2,250,000  25,000  (1.11)
April 2023 - June 2023 2,275,000  25,000  (1.11)
July 2023 - September 2023 2,300,000  25,000  (1.11)
October 2023 - December 2023 2,300,000  25,000  (1.11)
Period Volume (MMBtu) Volume
(MMBtu/d)
Wtd. Avg. Collar Price Ranges
($/MMBtu)(3)
Natural gas collars
July 2022 - September 2022 1,840,000  20,000  $3.50 - $3.97
October 2022 - December 2022 2,450,000 26,630  3.87 - 5.06
January 2023 - March 2023 4,950,000 55,000  4.09 - 7.47
April 2023 - June 2023 4,095,000 45,000  3.72 - 7.32
July 2023 - September 2023 4,140,000 45,000  3.72 - 7.32
October 2023 - December 2023 4,140,000 45,000  3.76 - 7.69
January 2024 - March 2024 1,820,000 20,000  3.25 - 5.31
(1)    These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2)    These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas, during each applicable monthly settlement period.
22

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(3)    These natural gas collars are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
Derivative Instrument Reporting. The Company’s oil and natural gas derivative instruments have not been designated as hedges for accounting purposes. Therefore, all gains and losses are recognized in the Company’s consolidated statements of operations. All derivative instruments are recorded at fair value in the consolidated balance sheets, other than derivative instruments that meet the “normal purchase normal sale” exclusion, and any fair value gains and losses are recognized in current period earnings.
The following table presents the impact of the Company’s derivative instruments in its consolidated statements of operations for the periods presented:
Three Months Ended June 30, Six Months Ended June 30,
(in thousands)
2022 2021 2022 2021
Net gain (loss) on derivative instruments
$ (34,134) $ (54,959) $ (163,657) $ (106,158)
Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives are included in the accompanying consolidated balance sheets as derivative assets and liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master netting agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The tables below summarize the fair value amounts and the classification in the consolidated balance sheets of the Company’s derivative contracts outstanding at the respective balance dates, as well as the gross recognized derivative assets, liabilities and offset amounts:
Balance Sheet Classification Gross Fair Value Asset/Liability Amounts
Gross Amounts Offset(1)
Net Recognized Fair Value Assets/Liabilities
(in thousands)
June 30, 2022
Derivative Assets
Commodity contracts
Prepaid and other current assets $ 26,356  $ (26,211) $ 145 
Other noncurrent assets 21,874  (17,995) 3,879 
Derivative Liabilities
Commodity contracts
Derivative instruments 109,752  (26,211) 83,541 
Other noncurrent liabilities 20,518  (17,995) 2,523 
December 31, 2021
Derivative Assets
Commodity contracts
Prepaid and other current assets $ 3,284  $ (3,284) $ — 
Other noncurrent assets 585 $ (345) 240
Derivative Liabilities
Commodity contracts
Derivative instruments $ 38,434  $ (3,284) $ 35,150 
Other noncurrent liabilities 345  (345) — 
(1)     The Company has agreements in place with each of its counterparties that allow for the financial right of offset for derivative assets against derivative liabilities at settlement or in the event of a default under the agreements or 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.
23

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

In addition, the Company is exposed to credit risk associated with its derivative contracts from non-performance by its counterparties. The Company mitigates its exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member under CRP’s Credit Agreement as referenced above.
Note 8—Fair Value Measurements
Recurring Fair Value Measurements
The Company follows ASC Topic 820, Fair Value Measurement and Disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

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

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

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

The following table presents, for each applicable level within the fair value hierarchy, the Company’s net derivative assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis:
(in thousands)
Level 1 Level 2 Level 3
June 30, 2022
Total assets
$ —  $ 4,024  $ — 
Total liabilities
—  86,064  — 
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
24

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

which the carrying amount of proved properties exceeds their estimated fair value. The Company reviews its oil and natural gas properties on a field-by-field basis.
The Company calculates the estimated fair values of its oil and natural gas properties using an income approach that is based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the expected future net cash flows used for the impairment review and the related fair value measurement of oil and natural gas proved properties include estimates of: (i) oil and gas reserves; (ii) future production decline rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; and (v) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management.
Asset Retirement Obligations. The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO include the estimated future costs to plug and abandon oil and gas properties and reserve lives. Refer to Note 5—Asset Retirement Obligations for additional information on the Company’s ARO.
Other Financial Instruments
The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate their fair values because of the short-term maturities and/or liquid nature of these assets and liabilities.
The Company’s senior notes and borrowings under its Credit Agreement 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:
June 30, 2022 December 31, 2021
Carrying Value Principal Amount Fair Value Carrying Value Principal Amount Fair value
Credit Facility due 2027(1)
$ —  $ —  $ —  $ 25,000  $ 25,000  $ 25,000 
5.375% Senior Notes due 2026(2)
286,083  289,448  264,129  285,666  289,448  286,554 
6.875% Senior Notes due 2027(2)
351,164  356,351  337,643  350,712  356,351  361,696 
3.25% Convertible Notes due 2028(2)
164,602  170,000  212,577  164,187  170,000  215,279 
(1)     The carrying values of the amounts outstanding under CRP’s Credit Agreement approximate fair value because its variable interest rates are tied to current market rates and the applicable credit spreads represent current market rates for the credit risk profile of the Company.
(2)    The carrying values include associated unamortized debt issuance costs and any debt discounts as reflected in the consolidated balance sheets. The fair values are determined using quoted market prices for these debt securities, a Level 1 classification in the fair value hierarchy, and are based on the aggregate principal amount of the senior notes outstanding.
Note 9—Shareholders' Equity
Stock Repurchase Program
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 six months ended June 30, 2022. Due to restrictions related to the Merger, the Company has been unable to make or initiate any share repurchases under the Repurchase Program since the announcement and therefore, will not be able to begin repurchasing its shares until the pending Merger closes or is otherwise terminated.
Note 10—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
25

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 June 30, Six Months Ended June 30,
(in thousands, except per share data) 2022 2021 2022 2021
Net income (loss) $ 191,826  $ (25,055) $ 207,628  $ (59,700)
Add: Interest on Convertible Senior Notes, net of tax 1,306  —  2,611  — 
Adjusted net income (loss) $ 193,132  $ (25,055) $ 210,239  $ (59,700)
Basic weighted average shares of Common Stock outstanding 284,992  279,185  284,922  279,061 
Add: Dilutive effects of equity awards and ESPP shares 8,038  —  7,897  — 
Add: Dilutive effects of Convertible Senior Notes 27,074  —  27,074  — 
Diluted weighted average shares of Common Stock outstanding 320,104  279,185  319,893  279,061 
Basic net earnings (loss) per share of Common Stock $ 0.67  $ (0.09) $ 0.73  $ (0.21)
Diluted net earnings (loss) per share of Common Stock $ 0.60  $ (0.09) $ 0.66  $ (0.21)
The 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 June 30, Six Months Ended June 30,
(in thousands) 2022
2021(1)
2022
2021(1)
Out-of-the-money stock options 2,049  2,241  2,073  2,267 
Restricted stock —  8,769  —  9,167 
Performance stock units —  —  224  199 
Employee Stock Purchase Plan —  68  —  54 
Convertible Senior Notes —  27,074  —  27,074 
Warrants —  8,000  —  8,000 
(1)    The Company recognized a net loss during the three and six months ended June 30, 2021, and therefore all potentially dilutive securities were anti-dilutive and excluded from the calculation of diluted net earnings per share.
Note 11—Transactions with Related Parties
    Riverstone Investment Group LLC and its affiliates (“Riverstone”) beneficially own a more than 10% equity interest in the Company and are therefore considered related parties. The Company has a marketing agreement with Lucid Energy Delaware, LLC (“Lucid”), an affiliate of Riverstone. The Company believes that the terms of the marketing agreement with Lucid are no less favorable to either party than those held with unaffiliated parties.
The following table summarizes the revenues recognized and the associated processing fees incurred from this marketing agreement as included in the consolidated statements of operations for the periods indicated, as well as the related net receivables outstanding as of the balance sheet dates:
Three Months Ended June 30, Six Months Ended June 30,
(in thousands) 2022 2021 2022 2021
Oil and gas sales $ 9,107  $ 3,056  $ 18,590  $ 4,132 
Gathering, processing and transportation expenses 2,150  1,636  4,669  2,841 
(in thousands) June 30, 2022 December 31, 2021
Accounts receivable, net(1)
$ 3,889  $ 5,562 
(1) Represents amounts due from Lucid and are presented net of unpaid processing fees as of the indicated period end date.
26

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 12—Commitments and Contingencies
Commitments
The Company routinely enters into, extends or amends operating agreements in the ordinary course of business. During the six months ended June 30, 2022, the Company entered into a two-year purchase agreement to buy frac’ sand used in its well fracture stimulation process. Under the terms of this take-or-pay agreement, the Company is obligated to purchase a minimum volume of frac’ sand at a fixed price. The obligation is $39.1 million, which represents the minimum financial commitment pursuant to the terms of the contract from June 30, 2022 through March 31, 2024. There has been no other material, non-routine changes in commitments during the six months ended June 30, 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.
Note 13—Revenues
Revenue from Contracts with Customers
Crude oil, natural gas and NGL sales are recognized at the point that control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials. As a result, the Company’s realized prices of oil, natural gas, and NGLs fluctuate to remain competitive with other available oil, natural gas, and NGLs supplies both globally (in the case of crude oil) and locally.
Oil and gas revenues presented within the consolidated statements of operations relate to the sale of oil, natural gas and NGLs as shown below:
Three Months Ended June 30, Six Months Ended June 30,
2022 2021 2022

2021
Operating revenues (in thousands):
Oil sales
$ 349,591  $ 177,105  $ 612,358  $ 310,831 
Natural gas sales
68,030  27,015  107,048  62,466 
NGL sales
55,033  28,457  100,525  51,671 
Oil and gas sales
$ 472,654  $ 232,577  $ 819,931  $ 424,968 
27

CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Oil sales
The Company’s crude oil sales contracts are generally structured whereby oil is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes title of the product. This delivery point is usually at the wellhead or at the inlet of a transportation pipeline. Revenue is recognized when control transfers to the purchaser at the delivery point based on the net price received from the purchaser. Any downstream transportation costs incurred by crude purchasers are reflected as a net reduction to oil sales revenues.
Natural gas and NGL sales
Under the Company’s natural gas processing contracts, liquids rich natural gas is delivered to a midstream gathering and processing entity at the inlet of the gas gathering system. The midstream processing entity gathers and processes the raw gas and then remits proceeds to Centennial for the resulting sales of NGLs, while the Company generally elects to take its residue gas product “in-kind” at the plant tailgate. For these contracts, the Company evaluates when control is transferred and revenue should be recognized. Where the Company has concluded that control transfers at the tailgate of the processing facility, fees incurred prior to transfer of control are presented as gathering, processing and transportation expenses (“GP&T”) within the consolidated statements of operations. Any transportation and fractionation costs incurred subsequent to the point of transfer of control are reflected as a net reduction to natural gas and NGL sales revenues presented in the table above.
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 June 30, 2022 and December 31, 2021, such receivable balances were $114.2 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 and six months ended June 30, 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 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 14—Subsequent Events
Credit Facility
On July 15, 2022, CRP and the Company entered into the first amendment to its Credit Agreement (the “Amendment”). The Amendment, among other things, waives compliance with certain restrictive covenants and provides the lenders’ consent to a planned Pre-Merger Reorganization (as defined within the Amendment) in order to enable the Merger. In addition, the Amendment increases the elected commitments under the Credit Agreement to $1.5 billion from $750 million and the borrowing base to $2.5 billion from $1.15 billion. The Amendment is subject to and effective as of the closing date of the Merger and will be terminated if the Merger has not occurred prior to November 30, 2022.

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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, the success of our pending merger transaction, 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 this Quarterly Report and 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 half of 2022, Russia’s invasion of Ukraine and global sanctions placed on Russia in response have created additional downward pressures on the supply of oil and natural gas. Meanwhile, demand for oil and gas has risen steadily throughout 2021 and 2022 due to the availability of COVID-19 vaccinations, fewer government mandated restrictions and the global-wide transition away from coal to natural gas. Despite governmental actions from several countries to release a portion of their strategic petroleum reserves, global oil inventories have continued to decline due to the resulting supply and demand imbalances. These factors, among others, have aided in the recovery of global commodity prices throughout 2021 and have led to heightened commodity prices in the first half 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 $9.46 per MMBtu on June 9, 2022, from a low of $1.33 per MMBtu on September 22, 2020.
    The oil and natural gas industry is cyclical, and it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, the continued effects from COVID-19 and variant strains of the virus, geopolitical events, federal and state government regulations, weather conditions, the global transition to alternative energy sources, supply chain constraints and other factors. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2020:
2020 2021 2022
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2
Crude oil (per Bbl) $ 46.19  $ 28.00  $ 40.93  $ 42.66  $ 57.84  $ 66.06  $ 70.56  $ 77.09  $ 94.40  $ 108.34 
Natural gas (per MMBtu) $ 1.88  $ 1.65  $ 1.95  $ 2.47  $ 3.44  $ 2.88  $ 4.28  $ 4.74  $ 4.60  $ 7.39 
Lower commodity prices 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
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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.
Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. In addition, the U.S. inflation rate has been steadily increasing during 2021 and 2022. These inflationary pressures may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise.
COVID-19 Outbreak
The COVID-19 outbreak and its development into a pandemic in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, vendors, suppliers and the communities in which we operate. Our operational employees have been and are currently able to work on site, while certain non-operational employees have been working remotely part-time and then also reporting to our offices on a 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
Pending Merger
On May 19, 2022, we entered into a Business Combination Agreement (the “Business Combination Agreement”) with Colgate Energy Partners III, LLC (“Colgate”), which provides for the combination of Centennial and Colgate in a merger of equals transaction (the “Merger”). Colgate is an independent oil and gas company focused on the acquisition, development, exploration and production of oil and natural gas properties in the Permian Basin. Colgate owns approximately 105,000 net leasehold acres and 25,000 net royalty acres in Reeves and Ward counties in Texas and Eddy County in New Mexico. We believe that the Merger will provide significant increases to operational and financial scale, drive accretion across our key financial and operating metrics, and enhance the combined company’s shareholder returns.
Pursuant to the Business Combination Agreement, all membership interests in CRP issued and outstanding will be converted into units in the surviving company (“Surviving Company Units”) equal to the number of shares of our Class A common stock (“Common Stock”) that are outstanding at such time, and all of the membership interest in Colgate will be exchanged for 269,300,000 shares of Class C common stock (with underlying Surviving Company Units) and $525 million in cash. The shares of Class C common stock will represent a noncontrolling interest in the Surviving Company.
The transaction has been unanimously approved by the Boards of Directors of both companies. The definitive proxy statement has been filed with the SEC and the shareholder meeting is scheduled for August 29, 2022, where the Merger will be voted on by our shareholders. The Merger is expected to close shortly after the shareholder meeting subject to customary closing conditions, including, among others, receipt of the required approvals from our shareholders.
Operational Highlights
We operated a two-rig drilling program during the first six months of 2022, which enabled us to complete and bring online 31 gross operated wells with an average effective lateral length of approximately 9,100 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 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. Due to restrictions related to the Merger, we have been unable to make or initiate any share repurchases under the Repurchase Program since the announcement and therefore, we will not be able to begin repurchasing our shares until the pending Merger closes or is otherwise terminated.
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On July 15, 2022, we entered into the first amendment to our Credit Agreement (the “Amendment”). The Amendment, among other things, waives compliance with certain restrictive covenants and provides the lenders’ consent to a planned Pre-Merger Reorganization (as defined within the Amendment) in order to enable the Merger. In addition, the Amendment increases the elected commitments under our Credit Agreement to $1.5 billion from $750 million and the borrowing base to $2.5 billion from $1.15 billion. The Amendment is subject to and effective as of the closing date of the Merger and will be terminated if the Merger has not occurred prior to November 30, 2022.
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Results of Operations
Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 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 June 30, Increase/(Decrease)
2022 2021 $ %
Net revenues (in thousands):
Oil sales $ 349,591  $ 177,105  $ 172,486  97  %
Natural gas sales 68,030  27,015  41,015  152  %
NGL sales 55,033  28,457  26,576  93  %
Oil and gas sales $ 472,654  $ 232,577  $ 240,077  103  %
Average sales prices:
Oil (per Bbl) $ 104.69  $ 60.99  $ 43.70  72  %
Effect of derivative settlements on average price (per Bbl) (16.97) (12.59) (4.38) (35) %
Oil net of hedging (per Bbl)
$ 87.72  $ 48.40  $ 39.32  81  %
Average NYMEX price for oil (per Bbl) $ 108.34  $ 66.06  $ 42.28  64  %
Oil differential from NYMEX (3.65) (5.07) 1.42  28  %
Natural gas (per Mcf) $ 6.22  $ 2.55  $ 3.67  144  %
Effect of derivative settlements on average price (per Mcf) (1.55) (0.09) (1.46) (1,622) %
Natural gas net of hedging (per Mcf)
$ 4.67  $ 2.46  $ 2.21  90  %
Average NYMEX price for natural gas (per Mcf) $ 7.39  $ 2.88  $ 4.51  157  %
Natural gas differential from NYMEX (1.17) (0.33) (0.84) (255) %
NGL (per Bbl) $ 44.77  $ 30.37  $ 14.40  47  %
Net production:
Oil (MBbls) 3,339  2,904  435  15  %
Natural gas (MMcf) 10,941  10,613  328  %
NGL (MBbls) 1,230  937  293  31  %
Total (MBoe)(1)
6,392  5,610  782  14  %
Average daily net production:
Oil (Bbls/d) 36,696  31,912  4,784  15  %
Natural gas (Mcf/d) 120,225  116,629  3,596  %
NGL (Bbls/d) 13,507  10,297  3,210  31  %
Total (Boe/d)(1)
70,240  61,647  8,593  14  %
(1)    Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
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Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the three months ended June 30, 2022 were $240.1 million (or 103%) higher than total net revenues for the three months ended June 30, 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 second quarter of 2022 compared to the same 2021 period by 72%, 144% and 47%, respectively. The 72% increase in the average realized oil price was mainly the result of higher (64%) NYMEX crude prices between periods, as well as improved oil differentials ($1.42 per Bbl narrower). The average realized sales price of natural gas increased 144% due to higher (157%) NYMEX gas prices between periods, partially offset by wider gas differentials ($0.84 per Mcf wider). The 47% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in the second quarter of 2022 as compared to the second quarter of 2021. The market prices for oil, natural gas and NGLs have all been impacted by global supply constraints for oil and gas throughout 2021 and 2022, as well as increasing demand worldwide as global economies emerge from COVID-19 era lockdowns and restrictions, as discussed in the market conditions section above.
Net production volumes for oil, natural gas and NGLs increased 15%, 3% and 31%, respectively, between periods. The increase in oil production resulted from our successful drilling program in the Delaware Basin. Since the second quarter of 2021, we placed 50 wells on production, which added 1,649 MBbls of net oil production to the three months ended June 30, 2022, as compared to 28 wells brought online since the second quarter of 2020 that added 872 MBbls of net oil production to the second quarter of 2021. These oil volume increases were partially offset by normal production decline across our existing wells. Natural gas and NGLs are produced concurrently with our crude oil volumes, which typically results in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold. However, the main processor of our raw gas operated in partial ethane-recovery during the second 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 June 30, Increase/(Decrease)
2022 2021 Change %
Operating costs (in thousands):
Lease operating expenses $ 28,900  $ 22,976  $ 5,924  26  %
Severance and ad valorem taxes 34,695  15,784  18,911  120  %
Gathering, processing and transportation expenses 25,756  19,494  6,262  32  %
Operating cost metrics:
Lease operating expenses (per Boe) $ 4.52  $ 4.10  $ 0.42  10  %
Severance and ad valorem taxes (% of revenue) 7.3  % 6.8  % 0.5  % %
Gathering, processing and transportation expenses (per Boe) $ 4.03  $ 3.47  $ 0.56  16  %
Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended June 30, 2022 increased $5.9 million compared to the three months ended June 30, 2021. Higher LOE for the second quarter of 2022 was primarily related to (i) a $2.9 million increase in electricity costs between periods due to electricity credits received during the second quarter of 2021 related to the severe winter storm in the Permian Basin (“Winter Storm Uri”) that were not similarly received in 2022; (ii) an increase in workover expense of $0.9 million between periods; and (iii) higher fixed and variable costs associated with our higher well count, which increased to 435 gross operated horizontal wells as of June 30, 2022 from 409 gross operated horizontal wells as of June 30, 2021. These increases were partially offset by lower water handling costs, which are associated with our higher level of recycling activity whereby produced water from our operated wells is recycled and then reused in our drilling and completion operations. This process results in significantly lower costs as compared to typical water disposal rates.
LOE per Boe was $4.52 for the second quarter of 2022, which represents an increase of $0.42 per Boe (or 10%) from the second quarter of 2021. This increase was primarily driven by per Boe increases associated with (i) higher electricity expenses between periods (discussed above); (ii) higher workover expense; and (iii) fixed and semi-variable costs, such as monthly equipment rentals, repair work, labor, and wellhead chemical costs, that increase at a higher rate than increases in production. These per Boe increases were partially offset by decreases in our water handling costs described above.
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Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended June 30, 2022 increased $18.9 million compared to the three months ended June 30, 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 second quarter of 2022 increased $17.6 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 $1.3 million due to higher tax assessments on our oil and gas reserve values.
Severance and ad valorem taxes as a percentage of total net revenues increased to 7.3% for the three months ended June 30, 2022 as compared to 6.8% 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, which levies higher severance tax rates than Texas, during the second quarter of 2022.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended June 30, 2022 increased $6.3 million as compared to the three months ended June 30, 2021. Similarly, GP&T increased on a per Boe basis from $3.47 for the second quarter of 2021 to $4.03 for the second quarter of 2022. These increases were mainly attributable to 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. This increase was partially offset by a higher portion of our 2022 oil and gas volumes being produced from our New Mexico wells, where our GP&T rates are currently lower than those in Texas.
Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A”) for the periods indicated: 
Three Months Ended June 30,
(in thousands, except per Boe data) 2022

2021
Depreciation, depletion and amortization $ 82,117  $ 73,429 
Depreciation, depletion and amortization per Boe $ 12.85  $ 13.09 
For the three months ended June 30, 2022, DD&A expense amounted to $82.1 million, an increase of $8.7 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 $10.2 million for the three months ended June 30, 2022. This was partially offset by our lower DD&A rate in the 2022 period, which decreased DD&A expense by $1.5 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 $12.85 for the second quarter of 2022 compared to $13.09 for the same period in 2021. This decrease in DD&A rate was primarily due to the Company continuing to complete wells with low finding and development costs and high quantities of associated proved developed reserves since the second quarter of 2021.
General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:
Three Months Ended June 30,
(in thousands) 2022 2021
Cash general and administrative expenses $ 12,434  $ 10,126 
Stock-based compensation - equity awards 6,106  4,260 
Stock-based compensation - liability awards (8,593) 14,421 
General and administrative expenses 9,947  28,807 
G&A expenses for the three months ended June 30, 2022 were $9.9 million compared to $28.8 million for the three months ended June 30, 2021. Lower G&A in the second quarter of 2022 was the result of a $21.2 million decrease in total stock-based compensation expense between periods. This decrease was primarily related to performance stock units granted in 2020 that are recorded at their respective fair value each balance sheet date, and such fair value decreased between periods. This decrease was slightly offset by an increase in cash G&A, which increased $2.3 million period over period due to higher payroll and other personnel costs.
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Merger and integration expense. Merger and integration expense for the three months ended June 30, 2022 was $5.7 million and includes costs incurred for the pending Merger consisting primarily of legal and advisory fees. See Note 2—Business Combination for further details regarding the pending Merger.
Impairment and Abandonment Expense. During the three months ended June 30, 2022, impairment and abandonment expense was $0.5 million as compared to $9.2 million during the three months ended June 30, 2021. Both periods consist solely of amortization of leasehold expiration costs associated with individually insignificant unproved properties.
Exploration and Other Expenses. The following table summarizes our exploration and other expenses for the periods indicated:
Three Months Ended June 30,
(in thousands) 2022

2021
Geological and geophysical costs $ 1,534  $ 1,173 
Stock-based compensation - equity awards 551  221 
Stock-based compensation - liability awards —  239 
Other expenses (131) 131 
Exploration and other expenses $ 1,954  $ 1,764 
Exploration and other expenses were $2.0 million for the three months ended June 30, 2022 compared to $1.8 million for the three months ended June 30, 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 second quarter of 2022.
Interest Expense. The following table summarizes our interest expense for the periods indicated:
Three Months Ended June 30,
(in thousands)
2022 2021
Credit facility $ 772  $ 2,762 
8.00% Senior Secured Notes due 2025
—  367 
5.375% Senior Notes due 2026 3,889  3,889 
6.875% Senior Notes due 2027 6,125  6,125 
3.25% Convertible Senior Notes due 2028 1,381  1,381 
Amortization of debt issuance costs and debt discount 2,734  1,040 
Interest capitalized (575) (382)
Total $ 14,326  $ 15,182 
Interest expense decreased $0.9 million for the three months ended June 30, 2022 as compared to the three months ended June 30, 2021 primarily due to (i) $2.0 million in lower interest incurred on our Credit Agreement due to lower borrowings outstanding during the 2022 period, and (ii) $0.4 million in interest expense on our Senior Secured Notes due 2025 that was incurred in the second quarter of 2021 but not in the 2022 period, as these notes were redeemed in April of 2021. These decreases were partially offset by additional debt issuance costs amortized during the second quarter of 2022 related to fees incurred for an incremental commitment letter we entered into in connection with the Merger.
Our weighted average borrowings outstanding under our Credit Agreement were $5.4 million versus $289.8 million for the three months ended June 30, 2022 and 2021, respectively. Our Credit Agreement’s weighted average effective interest rate was 2.7% and 3.3% for the three months ended June 30, 2022 and 2021, respectively.
Gain (loss) on extinguishment of debt. During the three months ended June 30, 2021, we redeemed at par all of our $127.1 million aggregate principal amount of Senior Secured Notes outstanding. In connection with this redemption, we recorded a loss on debt extinguishment of $22.2 million related to the write-off of all unamortized debt issuance costs and debt discounts associated with these notes.
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Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding and (ii) monthly cash settlements on any closed out hedge positions during the period.
The following table presents gains and losses on our derivative instruments for the periods indicated:
Three Months Ended June 30,
(in thousands)
2022 2021
Realized cash settlement gains (losses)
$ (73,648) $ (37,513)
Non-cash mark-to-market derivative gain (loss)
39,514  (17,446)
Total
$ (34,134) $ (54,959)
Income Tax (Expense) Benefit. The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated:
Three Months Ended June 30,
(in thousands)
2022 2021
Income (loss) before income taxes
$ 233,313  $ (25,055)
Income tax (expense) benefit
(41,487) — 
Our provisions for income taxes for the three months ended June 30, 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 June 30, 2022, we generated pre-tax net income of $233.3 million and recorded income tax expense of $41.5 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the partial release of our deferred tax valuation allowance due to the generation of net income in the current year.
For the three months ended June 30, 2021, we recognized a deferred tax asset valuation allowance of $7.6 million against net operating losses (“NOLs”) we generated during the quarter, and such NOLs were estimated at such time as unlikely to be realized in future periods. The increase in the valuation allowance was the primary factor reducing our income tax benefit (based on the U.S. statutory rate) to zero for the second quarter of 2021.
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Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 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:
Six Months Ended June 30, Increase/(Decrease)
2022 2021 $ %
Net revenues (in thousands):
Oil sales $ 612,358  $ 310,831  $ 301,527  97  %
Natural gas sales 107,048  62,466  44,582  71  %
NGL sales 100,525  51,671  48,854  95  %
Oil and gas sales
$ 819,931  $ 424,968  $ 394,963  93  %
Average sales prices:
Oil (per Bbl) $ 97.42  $ 57.08  $ 40.34  71  %
Effect of derivative settlements on average price (per Bbl) (15.03) (11.12) (3.91) (35) %
Oil net of hedging (per Bbl)
$ 82.39  $ 45.96  $ 36.43  79  %
Average NYMEX price for oil (per Bbl) $ 101.37  $ 61.95  $ 39.42  64  %
Oil differential from NYMEX (3.95) (4.87) 0.92  19  %
Natural gas (per Mcf) $ 5.13  $ 3.13  $