UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
ý QUARTERLY REPORT PURSUANT TO SECTION☒Quarterly report pursuant to Section 13 ORor 15(d) OF THE SECURITIES EXCHANGE ACT OFof the Securities Exchange Act of 1934

For the quarterly period ended SeptemberJune 30, 20172023
OR
o TRANSITION REPORT PURSUANT TO SECTION☐Transition report pursuant to Section 13 ORor 15(d) OF THE SECURITIES EXCHANGE ACT OFof the Securities Exchange Act of 1934


For the transition period from                     to                   
Commission file number 001-37697

CENTENNIAL RESOURCE DEVELOPMENT, INC.PERMIAN RESOURCES CORPORATION
(Exact Name of Registrant as Specified in its Charter)
Delaware
47-5381253
Delaware47-5381253
(State of Incorporation)(I.R.S. Employer Identification Number)
1001 Seventeenth Street, Suite 1800, Denver, Colorado80202
(Address of Principal Executive Offices)(Zip Code)No.)
(720) 499-1400300 N. Marienfeld St., Suite 1000
Midland, Texas 79701
(Registrant’s Telephone Number, Including Area Code)telephone number, including area code): (432) 695-4222
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading SymbolName of each exchange on which registered
Class A Common Stock, par value $0.0001 per sharePRNew York Stock Exchange
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 ý☒ No o☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes ý☒ No o☐
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 filero
Accelerated filero
Non-accelerated filerý
(Do not check if a smaller reporting company)
Smaller reporting company o
Emerging growth companyý
☒☐☐☐☐
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. o☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o☐ No ý☒
As of OctoberJuly 31, 2017,2023, there were 256,731,091565,955,410 shares of total common stock outstanding, including 321,327,851 shares of Class A Common Stock, par value $0.0001 per share, and 19,155,921244,627,559 shares of Class C Common Stock, par value $0.0001 per share, outstanding.
share.



TABLE OF CONTENTS
Page
3
5
7
Page
3
Glossary of Certain Other Terms
5
Cautionary Statement Concerning Forward-Looking Statements
6
Part I—FINANCIAL INFORMATION
8
Item 1.
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GLOSSARY OF OILUNITS OF MEASUREMENTS AND NATURAL GASINDUSTRY 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.

Bbls/Bbl/d. BarrelsOne 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. InstallationThe process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, for productionas well as perforation and fracture stimulation to initiate production.
Development well. A well drilled within the proved area of an oil or natural gas or, inreservoir to the casedepth of a dry well,stratigraphic horizon known to reporting to the appropriate authority that the well has been abandoned.be productive.

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

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

DryExploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be incapableproductive of producing hydrocarbonsoil or natural gas in sufficient quantities such that proceeds fromanother reservoir.
Extension well. A well drilled to extend the salelimits of such production exceed production expenses and taxes.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.

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

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

Henry Hub. The Henry Hub pipeline is pricing point for natural gas contracts traded on NYMEX used as a benchmark in natural gas pricing.
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).
MBblsMBbl. One thousand barrels of crude oil, condensate or NGLs.

MBoe. One thousand Boe.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One Mcf per day.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

NGL.NGL. Natural gas liquids. HydrocarbonsThese are naturally occurring substances found in natural gas, which may be extracted as liquefied petroleum gasincluding ethane, butane, isobutane, propane and natural gasoline.gasoline, that can be collectively removed from produced natural gas, separated in these substances and sold.

NYMEX. The New York Mercantile Exchange.

NYSE. The New York Stock 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.

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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 all expected quality, transportation and demand adjustments.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. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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.
Working interestWellbore. The right granted to the lessee ofhole drilled by a property to develop and produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

WTI. West Texas Intermediate.



GLOSSARY OF CERTAIN OTHER TERMS
The following are definitions of certain other termsdrill bit that are used in this Quarterly Report on Form 10-Q:
Business Combination. The acquisition of approximately 89% of the outstanding membership interests in CRP from the Centennial Contributors, which closed on October 11, 2016, and the other transactions contemplated by the Contribution Agreement.
Celero. Celero Energy Company, LP, a Delaware limited partnership.
Centennial Contributors. CRD, NGP Follow-On and Celero, collectively.
The Company, we, our or us. (i) Centennial Resource Development, Inc. and its subsidiaries, including CRP, following the closing of the Business Combination and (ii) Silver Run Acquisition Corporation prior to the closing of the Business Combination.
Class A Common Stock. Our Class A Common Stock, par value $0.0001 per share.
Class C Common Stock. Our Class C Common Stock, par value $0.0001 per share, which was issued to the Centennial Contributors in connection with the Business Combination.
Contribution Agreement. The Contribution Agreement, dated as of July 6, 2016, among the Centennial Contributors, CRP and NewCo, as amended by Amendment No. 1 thereto, dated as of July 29, 2016, and the Joinder Agreement, dated as of October 7, 2016, by the Company.
CRD. Centennial Resource Development, LLC, a Delaware limited liability company.
CRP. Centennial Resource Production, LLC, a Delaware limited liability company.
GMT Acquisition. Our acquisition of certain undeveloped acreage and producingis equipped for oil and natural gas properties of GMT Exploration Company LLC, which closedproduction 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 June 8, 2017.
IPO. Our initial public offering of units, which closed on February 29, 2016.
NewCo. New Centennial, LLC,the property and to a Delaware limited liability company controlled by affiliates of Riverstone.
NGP Follow-On. NGP Centennial Follow-On LLC, a Delaware limited liability company.
Private Placement Warrants. Our 8,000,000 outstanding warrants for the purchase of shares of Class A Common Stock, which were purchased by our Sponsor in a private placement simultaneously with the closing of our IPO.
Public Warrants. Warrants for the purchase of shares of Class A Common Stock sold as part of the Units in our IPO, all of which have been exercised or redeemed and are no longer outstanding.
Riverstone. Riverstone Investment Group LLC and its affiliates, including our Sponsor, collectively.
Series B Preferred Stock. Our Series B Preferred Stock, par value $0.0001 per share, all outstanding shares of which were converted into 26,100,000 shares of Class A Common Stock on May 25, 2017.
Silverback. Silverback Exploration, LLC and Silverback Operating, LLC, collectively.
Silverback Acquisition. Our acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback, which closed on December 28, 2016.
Sponsor. Our sponsor, Silver Run Sponsor, LLC, a Delaware limited liability company and an affiliate of Riverstone.
Units. Our units sold in our IPO, each of which consisted of one share of Class A Common Stockproduction, subject to all royalties and one-thirdother burdens and to all costs of one Public Warrant.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 report,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 Form 10-Q,Quarterly Report, the words ”could,“could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project”“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'smanagement’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Item Item 1A. Risk Factors”Factors in this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, 2016 (“20162022 (the “2022 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;
•political and economic conditions in or affecting other producing regions or countries, including the Middle East, Russia, Eastern Europe, Africa and South America;
•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;
•our business strategy; strategy and future drilling plans; 
•our reserves; 
our drilling prospects, inventories, projectsreserves and programs; 
our ability to replace the reserves we produce through drilling and property acquisitions; 
•our drilling prospects, inventories, projects and programs; 
•our financial strategy, return of capital program, 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 ability to identify, complete and effectively integrate acquisitions of properties or businesses;
•our ability to realize the anticipated benefits and synergies from the Merger and effectively integrate the assets of the Company and Colgate (as such capitalized terms are defined below);
•our hedging strategy and results; 
our future drilling plans; 
•our competition and government regulations; 
•our ability to obtain permits and governmental approvals; 
•our pending legal or environmental matters; 
our•the marketing and transportation of our oil, natural gas and NGLs; 
•our leasehold or business acquisitions; 
our costs•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; 
•our ability to make dividends, distributions and share repurchases;
•uncertainty regarding our future operating results; and 
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•our plans, objectives, expectations and intentions contained in this Form 10-QQuarterly Report that are not historical.
All forward-looking statements speak only as of the date of this Form 10-Q. You should not place undue reliance onWe caution you that these forward-looking statements. These forward-looking statements are subject to a numberall of the risks and uncertainties, most of which are difficult to predict and assumptions, includingmany 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 thosecommodity price volatility, inflation, lack of availability of drilling and production equipment and services, risks relating to the merger of the company with Colgate Energy Partners III, LLC (the “Merger”), 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 underin “Item 1A. Risk Factors” in this Quarterly Report and our 20162022 Annual Report. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make.
Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Although we believe that our plans, intentions and expectations reflected inShould one or suggested bymore of the forward-looking statements we makerisks or uncertainties described in this Form 10-Q are reasonable, we can give no assurance that these plans, intentionsQuarterly Report or expectations will be achievedour 2022 Annual Report occur, or occur, andunderlying assumptions prove incorrect, our actual results and plans could differ materially and adversely from those anticipated or implied by theexpressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this Form 10-QQuarterly 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 Form 10-Q.Quarterly Report.





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PART I. FINANCIAL INFORMATION
Item 1.    Financial Statements
CENTENNIAL RESOURCE DEVELOPMENT, INC. PERMIAN RESOURCES CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)
(in thousands, except share and per share amounts)
 September 30, 2017 December 31, 2016
ASSETS   
Current assets   
Cash and cash equivalents$2,581
 $134,083
Accounts receivable, net50,207
 14,734
Derivative instruments383
 431
Prepaid and other current assets6,104
 2,078
Total current assets59,275
 151,326
Oil and natural gas properties, successful efforts method   
Unproved properties2,008,902
 1,905,661
Proved properties1,306,873
 605,853
Accumulated depreciation, depletion and amortization(115,343) (14,436)
Total oil and natural gas properties, net3,200,432
 2,497,078
Other property and equipment, net3,897
 2,193
Total property and equipment, net3,204,329
 2,499,271
Noncurrent assets   
Derivative instruments242
 —
Other noncurrent assets10,766
 1,045
Total assets$3,274,612
 $2,651,642
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities   
Accounts payable and accrued expenses$136,495
 $86,100
Derivative instruments450
 5,361
Total current liabilities136,945
 91,461
Noncurrent liabilities   
Revolving credit facility165,000
 —
Asset retirement obligations9,328
 7,226
Deferred tax liability17,302
 —
Derivative instruments—
 20
Total liabilities328,575
 98,707
Shareholders’ equity   
Preferred stock, $0.0001 par value, 1,000,000 shares authorized:   
Series A: 1 share issued and outstanding—
 —
Series B: no shares issued and outstanding at September 30, 2017 and 104,400 shares issued and outstanding at December 31, 2016—
 —
Common stock, $0.0001 par value, 620,000,000 shares authorized:   
Class A: 257,760,091 shares issued and 256,670,839 shares outstanding at September 30, 2017 and 201,091,646 shares issued and 200,835,049 shares outstanding at December 31, 201626
 20
Class C: 19,155,921 shares issued and outstanding2
 2
Additional paid-in capital2,704,298
 2,364,049
Retained earnings (accumulated deficit)36,103
 (8,929)
Total shareholders’ equity2,740,429
 2,355,142
Noncontrolling interest205,608
 197,793
Total equity2,946,037
 2,552,935
Total liabilities and shareholders’ equity$3,274,612
 $2,651,642
June 30, 2023December 31, 2022
ASSETS
Current assets
Cash and cash equivalents$18,280 $59,545 
Accounts receivable, net309,624 282,846 
Derivative instruments87,737 100,797 
Prepaid and other current assets10,396 20,602 
Total current assets426,037 463,790 
Property and Equipment
Oil and natural gas properties, successful efforts method
Unproved properties1,415,969 1,424,744
Proved properties9,691,058 8,869,174
Accumulated depreciation, depletion and amortization(2,811,580)(2,419,692)
Total oil and natural gas properties, net8,295,447 7,874,226
Other property and equipment, net38,731 15,173
Total property and equipment, net8,334,178 7,889,399 
Noncurrent assets
Operating lease right-of-use assets62,049 64,792 
Other noncurrent assets104,061 74,611
TOTAL ASSETS$8,926,325 $8,492,592 
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses$661,748 $562,156 
Operating lease liabilities36,160 29,759 
Derivative instruments354 1,998 
Other current liabilities24,462 11,656 
Total current liabilities722,724 605,569
 Noncurrent liabilities
Long-term debt, net2,060,070 2,140,798 
Asset retirement obligations44,546 40,947 
Deferred income taxes78,685 4,430 
Operating lease liabilities27,894 41,341 
Other noncurrent liabilities66,396 3,211 
Total liabilities3,000,315 2,836,296
Commitments and contingencies (Note 12)
Shareholders’ equity
Common stock, $0.0001 par value, 1,500,000,000 shares authorized:
Class A: 325,446,375 shares issued and 319,646,487 shares outstanding at June 30, 2023 and 298,640,260 shares issued and 288,532,257 shares outstanding at December 31, 202233 30 
Class C: 244,632,559 shares issued and outstanding at June 30, 2023 and 269,300,000 shares issued and outstanding at December 31, 202224 27 
Additional paid-in capital2,944,785 2,698,465 
Retained earnings (accumulated deficit)363,881 237,226 
Total shareholders' equity3,308,723 2,935,748 
Noncontrolling interest2,617,287 2,720,548 
Total equity5,926,010 5,656,296 
TOTAL LIABILITIES AND EQUITY$8,926,325 $8,492,592 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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CONDENSED



PERMIAN RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(in thousands, except per share data)
Three Months Ended June 30,Six Months Ended June 30,
Successor  Predecessor Successor  Predecessor2023202220232022
For the Three Months Ended September 30, 2017  For the Three Months Ended September 30, 2016 For the Nine Months Ended September 30, 2017  For the Nine Months Ended September 30, 2016
Net revenues         
Oil sales$87,286
  $23,388
 $204,702
  $56,975
Natural gas sales12,852
  2,629
 33,226
  5,717
NGL sales11,473
  1,304
 25,844
  3,097
Total net revenues111,611
  27,321
 263,772
  65,789
Operating revenues Operating revenues
Oil and gas salesOil and gas sales$623,398 $472,654 $1,239,666 $819,931 
Operating expenses         Operating expenses
Lease operating expenses11,373
  3,656
 26,924
  10,295
Lease operating expenses82,991 28,900 157,523 57,634 
Severance and ad valorem taxes6,448
  1,432
 14,358
  3,523
Severance and ad valorem taxes48,927 34,695 97,436 59,746 
Gathering, processing and transportation expenses9,925
  1,787
 22,572
  4,375
Gathering, processing and transportation expenses21,753 25,756 37,235 47,647 
Depreciation, depletion and amortization42,387
  18,454
 102,847
  60,939
Depreciation, depletion and amortization215,726 82,117 403,945 153,126 
Impairment and abandonment expenses—
  1,649
 (29)  2,546
Exploration expense1,622
  402
 4,092
  920
General and administrative expenses13,311
  4,848
 36,017
  9,735
General and administrative expenses52,736 9,947 88,210 40,550 
Merger and integration expenseMerger and integration expense4,350 5,685 17,649 5,685 
Impairment and abandonment expenseImpairment and abandonment expense244 506 489 3,133 
Exploration and other expensesExploration and other expenses5,263 1,954 9,637 4,261 
Total operating expenses85,066
  32,228
 206,781
  92,333
Total operating expenses431,990 189,560 812,124 371,782 
Total operating income (loss)26,545
  (4,907) 56,991
  (26,544)
Net gain (loss) on sale of long-lived assetsNet gain (loss) on sale of long-lived assets— (1,406)66 (1,324)
Income (loss) from operationsIncome (loss) from operations191,408 281,688 427,608 446,825 
Other income (expense)         Other income (expense)
Gain (loss) on sale of oil and natural gas properties(141)  15
 7,216
  11
Interest expense(1,015)  (1,983) (2,132)  (5,422)Interest expense(36,826)(14,326)(73,603)(27,480)
Net gain (loss) on derivative instruments(896)  1,741
 5,392
  (4,184)Net gain (loss) on derivative instruments20,601 (34,134)75,113 (163,657)
Other income—
  —
 —
  6
Other income (expense)(2,052)  (227) 10,476
  (9,589)Other income (expense)319 85 439 203 
Total other income (expense)Total other income (expense)(15,906)(48,375)1,949 (190,934)
Income (loss) before income taxes24,493
  (5,134) 67,467
  (36,133)Income (loss) before income taxes175,502 233,313 429,557 255,891 
Income tax (expense) benefit(8,233)  —
 (17,302)  406
Income tax (expense) benefit(26,548)(41,487)(60,802)(48,263)
Net income (loss)16,260
  (5,134) $50,165
  $(35,727)Net income (loss)148,954 191,826 368,755 207,628 
Less: Net income attributable to noncontrolling interest1,813
  —
 5,133
  —
Net income (loss) attributable to common shareholders$14,447
  $(5,134) $45,032
  $(35,727)
Income per share:         
Less: Net (income) loss attributable to noncontrolling interestLess: Net (income) loss attributable to noncontrolling interest(75,555)— (193,236)— 
Net income (loss) attributable to Class A Common StockNet income (loss) attributable to Class A Common Stock$73,399 $191,826 $175,519 $207,628 
Income (loss) per share of Class A Common Stock:Income (loss) per share of Class A Common Stock:
Basic$0.06
    $0.20
   Basic$0.23 $0.67 $0.57 $0.73 
Diluted$0.06
    $0.19
   Diluted$0.21 $0.60 $0.52 $0.66 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.



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CONDENSED



PERMIAN RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(in thousands)
 Successor  Predecessor
 For the Nine Months Ended September 30, 2017  For the Nine Months Ended September 30, 2016
Cash flows from operating activities:    
Net income (loss)$50,165
  $(35,727)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Depreciation, depletion and amortization102,847
  60,939
Stock-based compensation expense9,420
  —
Impairment and abandonment expenses(29)  2,546
Deferred tax expense (benefit)17,302
  (406)
(Gain) loss on sale of oil and natural gas properties(7,216)  (11)
Non-cash portion of derivative (gain) loss(5,126)  20,807
Amortization of debt issuance costs348
  363
Changes in operating assets and liabilities:    
(Increase) decrease in accounts receivable(28,172)  3,021
Increase in prepaid and other assets(12,890)  (165)
Increase in accounts payable and other liabilities10,501
  144
Net cash provided by operating activities137,150
  51,511
Cash flows from investing activities:    
Acquisition of oil and natural gas properties(419,471)  (55,566)
Drilling and development capital expenditures(354,515)  (45,203)
Purchases of other property and equipment(3,482)  (206)
Proceeds from sales of oil and natural gas properties10,714
  —
Net cash used in investing activities(766,754)  (100,975)
Cash flows from financing activities:    
Issuance of Class A common shares340,750
  —
Underwriters discount and offering costs(7,233)  —
Proceeds from revolving credit facility190,000
  55,000
Repayment of revolving credit facility(25,000)  (5,000)
Financing obligation—
  (1,894)
Debt issuance costs(415)  —
Net cash provided by financing activities498,102
  48,106
Net decrease in cash and cash equivalents(131,502)  (1,358)
Cash and cash equivalents, beginning of period134,083
  1,768
Cash and cash equivalents, end of period$2,581
  $410
Supplemental cash flow information    
Cash paid for interest$1,915
  $4,993
Supplemental non-cash activity    
Accrued capital expenditures included in accounts payable and accrued expenses$102,152
  $16,339
Asset retirement obligations incurred, including changes in estimate$1,016
  $206
Six Months Ended June 30,
2023

2022
Cash flows from operating activities:
       Net income (loss)$368,755 $207,628 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization403,945 153,126 
Stock-based compensation expense - equity awards53,565 12,202 
Stock-based compensation expense - liability awards— 5,127 
Impairment and abandonment expense489 3,133 
Deferred tax expense (benefit)57,199 47,663 
Net (gain) loss on sale of long-lived assets(66)1,324 
Non-cash portion of derivative (gain) loss3,901 47,131 
Amortization of debt issuance costs and debt discount6,278 4,226 
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable(11,888)(62,751)
(Increase) decrease in prepaid and other assets(3,969)(6,201)
Increase (decrease) in accounts payable and other liabilities8,495 42,491 
Net cash provided by operating activities886,704 455,099 
Cash flows from investing activities:
Acquisition of oil and natural gas properties, net(107,766)(2,592)
Drilling and development capital expenditures(686,556)(224,011)
Purchases of other property and equipment(29,050)(2,863)
Contingent considerations received related to divestiture60,000 — 
Proceeds from sales of oil and natural gas properties63,986 863 
Net cash used in investing activities(699,386)(228,603)
Cash flows from financing activities:
Proceeds from borrowings under revolving credit facility630,000 170,000 
Repayment of borrowings under revolving credit facility(715,000)(195,000)
Debt issuance costs(603)(8,533)
Proceeds from exercise of stock options230 8 
Share repurchase(29,418)— 
Dividends paid(47,619)— 
Distributions paid to noncontrolling interest owners(37,883)— 
Class A Common Stock repurchased from employees for taxes due upon share vestings(38,108)(1,259)
Net cash provided by (used in) financing activities(238,401)(34,784)
Net increase (decrease) in cash, cash equivalents and restricted cash(51,083)191,712 
Cash, cash equivalents and restricted cash, beginning of period69,932 9,935 
Cash, cash equivalents and restricted cash, end of period$18,849 $201,647 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONDENSED


PERMIAN RESOURCES CORPORATION
CONSOLIDATED STATEMENTSTATEMENTS OF SHAREHOLDERS’ EQUITYCASH FLOWS (unaudited)
(continued)
(in thousands)
Six Months Ended June 30,
2023

2022
Supplemental cash flow information
Cash paid for interest$71,387 $24,276 
Cash paid for income taxes3,603 600 
Supplemental non-cash activity
Accrued capital expenditures included in accounts payable and accrued expenses242,782 63,486 
Deferred tax liability assumed in asset acquisition24,801 — 
Asset retirement obligations incurred, including revisions to estimates1,207 389 
Dividends payable2,302 — 
 Common Stock Preferred Stock          
 Class A Class C Series A Series B Additional Paid-In Capital Retained Earnings (Accumulated Deficit) Total Shareholders’ Equity Noncontrolling Interest Total Equity
 Shares Amount Shares Amount Shares Amount Shares Amount     
Balance at December 31, 2016201,092
 $20
 19,156
 $2
 —
 $—
 104
 $—
 $2,364,049
 $(8,929) $2,355,142
 $197,793
 $2,552,935
Warrants exercised6,236
 1
 —
 —
 —
 —
 —
 —
 (1) —
 —
 —
 —
Restricted stock issued841
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Restricted stock forfeited(9) —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Conversion of Series B preferred shares to Class A common shares26,100
 3
 —
 —
 —
 —
 (104) —
 (3) —
 —
 —
 —
Sale of unregistered Class A common shares23,500
 2
 —
 —
 —
 —
 —
 —
 340,748
   340,750
 —
 340,750
Underwriters' discount and offering expense—
 —
 —
 —
 —
 —
 —
 —
 (7,233) —
 (7,233) —
 (7,233)
Stock-based compensation—
 —
 —
 —
 —
 —
 —
 —
 9,420
 —
 9,420
 
 9,420
Change in equity due to issuance of shares by Centennial Resource Production, LLC—
 —
 —
 —
 —
 —
 —
 —
 (2,682) —
 (2,682) 2,682
 —
Net income—
 —
 —
 —
 —
 —
 —
 —
 —
 45,032
 45,032
 5,133
 50,165
Balance at September 30, 2017257,760
 $26
 19,156
 $2
 —
 $—
 —
 $—
 $2,704,298
 $36,103
 $2,740,429
 $205,608
 $2,946,037
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,
20232022
Cash and cash equivalents$18,280 $201,092 
Restricted cash(1)
569 555 
Total cash, cash equivalents and restricted cash$18,849 $201,647 
(1)    Included in Prepaid and other current assets as of June 30, 2023 and June 30, 2022 in the consolidated balance sheets.

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



10
CENTENNIAL RESOURCE DEVELOPMENT, INC.
Table of Contents




PERMIAN RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)
(in thousands)

Common StockAdditional Paid-In CapitalRetained Earnings (Accumulated Deficit)Total Shareholders’ EquityNon-controlling InterestTotal Equity
Class AClass C
SharesAmountSharesAmount
Balance at December 31, 2022298,640 $30 269,300 $27 $2,698,465 $237,226 $2,935,748 $2,720,548 $5,656,296 
Restricted stock issued359 — — — — — — — — 
Restricted stock forfeited(298)— — — — — — — — 
Stock purchased from employees for taxes due upon share vesting(3,384)— — — (32,160)— (32,160)— (32,160)
Stock option exercises39 — — — 231 — 231 — 231 
Issuance of Common Stock under Employee Stock Purchase Plan56 — — — 241 — 241 — 241 
Performance stock vested and issued5,406 — — — — — — — — 
Stock-based compensation - equity awards— — — — 17,871 — 17,871 — 17,871 
Dividends— — — — — (15,669)(15,669)— (15,669)
Distributions to noncontrolling interest owners— — — — — — — (13,950)(13,950)
Share repurchase— — (2,750)— — — — (29,418)(29,418)
Conversion of common shares from Class C to Class A, net of tax20,906 2 (20,906)(2)217,280 — 217,280 (214,864)2,416 
Equity impact from transactions effecting Common Units, net of tax benefit of $3.0 million— — — — (10,400)— (10,400)13,427 3,027 
Net income (loss)— — — — — 102,120 102,120 117,681 219,801 
Balance at March 31, 2023321,724 $32 245,644 $25 $2,891,528 $323,677 $3,215,262 $2,593,424 $5,808,686 
Restricted stock issued373 — — — — — — — — 
Restricted stock forfeited(357)— — — — — — — — 
Stock purchased from employees for taxes due upon share vesting(602)(1)— — (5,948)— (5,949)— (5,949)
Stock option exercises7 — — — (1)— (1)— (1)
Performance stock vested and issued3,290 1 — — (1)— — — — 
Stock-based compensation - equity awards— — — — 35,694 — 35,694 — 35,694 
Dividends— — — — — (33,195)(33,195)— (33,195)
Distributions to noncontrolling interest owners— — — — — — (24,558)(24,558)
Conversion of common shares from Class C to Class A, net of tax1,011 1 (1,011)(1)10,882 — 10,882 (10,825)57 
Equity impact from transactions effecting Common Units, net of tax expense of $3.7 million— — — — 12,631 — 12,631 (16,309)(3,678)
Net income (loss)— — — — — 73,399 73,399 75,555 148,954 
Balance at June 30, 2023325,446 $33 244,633 $24 $2,944,785 $363,881 $3,308,723 $2,617,287 $5,926,010 
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PERMIAN RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited) (continued)
(in thousands)

Common StockAdditional Paid-In CapitalRetained Earnings (Accumulated Deficit)Total Shareholders’ EquityNon-controlling InterestTotal Equity
Class AClass C
SharesAmountSharesAmount
Balance at December 31, 2021294,261 $29 — $— $3,013,017 $(262,326)$2,750,720 $— $2,750,720 
Restricted stock issued20 — — — — — — — — 
Restricted stock forfeited(52)— — — — — — — — 
Stock purchased from employees for taxes due upon share vesting(150)— — — (1,259)— (1,259)— (1,259)
Stock option exercises3 — — — 1 — 1 — 1 
Issuance of Common Stock under Employee Stock Purchase Plan53 — — — 268 — 268 — 268 
Stock-based compensation - equity awards— — — — 5,545 — 5,545 — 5,545 
Net income (loss)— — — — — 15,802 15,802 — 15,802 
Balance at March 31, 2022294,135 $29 — $— $3,017,572 $(246,524)$2,771,077 $— $2,771,077 
Restricted stock issued2,998 1 — — — — 1 — 1 
Restricted stock forfeited(75)— — — — — — — — 
Stock option exercises2 — — — 7 — 7 — 7 
Stock-based compensation - equity awards— — — — 6,657 — 6,657 — 6,657 
Net income (loss)— — — — — 191,826 191,826 — 191,826 
Balance at June 30, 2022297,060 $30 — $— $3,024,236 $(54,698)$2,969,568 $— $2,969,568 

The accompanying notes are an integral part of these unaudited consolidated financial statements.
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PERMIAN RESOURCES CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1—Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Centennial Resource Development, Inc. (the “Company” or “Centennial”) was originally incorporated in Delaware on November 4, 2015 as a special purpose acquisition company under the name Silver Run AcquisitionPermian Resources Corporation for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving the Company and one or more businesses.
On February 29, 2016, the Company consummated its initial public offering of Units each consisting of one share of Class A Common Stock and one-third of one Public Warrant. On October 11, 2016, the Company consummated the acquisition of approximately 89% of the outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company (“CRP” and such acquisition, the “Business Combination”). In connection with the closing of the Business Combination, the Company changed its name from "Silver Run Acquisition Corporation" to "Centennial Resource Development, Inc."
CRP was formed in August 2012 byis an affiliate of NGP Energy Capital Management, a family of energy-focused private equity investment funds, in connection with the acquisition of all of the oil and natural gas properties and certain other assets of Celero, which was formed in 2006 to focus on the development and acquisition of oil and natural gas properties located primarily in the Permian Basin of West Texas. Until the closing of the Business Combination, CRP operated as a privately-held independent oil and natural gas company.
company focused on the responsible acquisition, optimization and development of crude oil and associated liquids-rich natural gas reserves. 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”“Permian Resources” or the “Company” are to Centennial Resource Development, Inc.Permian Resources Corporation and its consolidated subsidiaries.subsidiary, Permian Resources Operating, LLC (“OpCo”).
Principles of Consolidation and Basis of Presentation
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) and the rules and regulations of the SEC.United States Securities and Exchange Commission (“SEC”) for interim financial reporting. Accordingly, certain disclosures required by U.S. GAAP and normally included in an Annual Report on Form 10-K have been omitted. Although management believes that our disclosures in these interimThe consolidated financial statements are adequate, theyand related notes included in this Quarterly Report should be read in conjunction with our 2016the 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, 2022 (the “2022 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 2022 Annual Report.
In the opinion of management, all normal, recurring adjustments and accruals considered necessary for a fair presentation of interim financial information,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. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying condensed consolidated financial statements. The Company has evaluated subsequent events through the date of this filing.
As a result of the Business Combination, the Company is the acquirer for accounting purposes, and CRP is the acquiree and accounting Predecessor. The Company’s financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination on October 11, 2016. The Business Combination was accounted for as a business combination using the acquisition method of accounting, and the Successor financial statements reflect a new basis of accounting that is based on the fair value of CRP’s net assets acquired. As a result of the application of the acquisition method of accounting as of the Business Combination, the financial statements for the Predecessor period and for the Successor period are presented on a different basis of accounting.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its majority owned subsidiary CRP,OpCo, and CRP’sOpCo’s wholly-owned subsidiaries. All intercompany balancesNoncontrolling interest represents third-party ownership in OpCo and transactions have been eliminated in consolidation.is presented as a component of equity. Refer to Note 9—Shareholders’ Equity and Noncontrolling Interest for a discussion of noncontrolling interest.
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 in 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.

12
Table 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 Contents
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


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 offor long-lived assets; (iii) impairment expense of unproved properties; (iv) depreciation, depletion and amortization; (iv)(v) asset retirement obligations; (v)(vi) determining fair value and allocating purchase price in connection with business combinations and asset acquisitions; (vi) valuation of derivative instruments; (vii) accrued revenuerevenues and related receivables; and (viii) accrued liabilities.liabilities; (ix) derivative valuations; (x) deferred income taxes; and (xi) determining the fair values of certain stock-based compensation awards.
Recently Issued Accounting StandardsLeases
The Company has operating leases for drilling rig contracts, office rental agreements and other wellhead equipment. During the six months ended June 30, 2023, the Company entered into additional wellhead equipment lease agreements for assets placed into service and recorded a lease right-of-use asset and related liability based on the present value of future lease payments over the equipment lease term. As of June 30, 2023, the Company had recorded $13.7 million of current operating lease liability and $14.0 million of noncurrent operating lease liability related to these wellhead equipment agreements.
In January 2017,April 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805): Clarifying the Definition ofCompany purchased an office building in Midland, Texas for $27.5 million, where it had previously been a Business. This update affects all reporting entities and the objectivelessee of the guidance is to assist with evaluation of whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The mandatory effective date for this update is for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The amendments should be applied prospectively on or after the effective date and disclosures are not required at transition. Early adoption is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance. The Company early adopted ASU 2017-01 in the second quarter of 2017. Refer to Note 2—Property Acquisitions for details of the GMT Acquisition.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This update applies to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years with early adoption permitted. This update should be applied using the retrospective transition method. Adoption of this standard will only affect the presentation of the Company’s statements of cash flows and will not have a material impact on its consolidated financial statements.
In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation. This update applies to all entities that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. The Company elected to early adopt this guidance in October 2016 in conjunction with the issuance of its equity awards.
In February 2016, the FASB issued ASU 2016-02, Leases. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leasesbuilding at the beginningtime of the earliest period presented usingpurchase. As a modified retrospective approach. Although the Company is still in the processresult, $9.3 million of evaluating the effect of adopting ASU 2016-02, the adoption is expected to result in the recognition ofoperating lease right-of-use assets and $13.6 million of operating lease liabilities on itswere removed from the consolidated balance sheet for current operating leases.as of June 30, 2023. As part of December 31, 2016,the building purchase, the Company had approximately $17.0assumed a ninety-nine year ground lease and accordingly, recorded a financing lease liability of $15.4 million as of contractual obligations related to its non-cancelable leases, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASU 2016-02.
In May 2014,June 30, 2023, which represents the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition, and most industry-specific guidance. The FASB subsequently issued various ASUs which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU 2014-09 and its amendments provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principlepresent value of the model isfuture payment obligations under this lease, that start at $0.8 million per year and escalate 2.5% annually until year 2076. The corresponding right-of-use asset recognized for this ground lease amounted to recognize revenue when control$15.3 million as of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. In addition, new qualitative and quantitative disclosure requirements aim to enable financial statement users to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 and its amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standards permitJune 30, 2023.

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CENTENNIAL RESOURCE DEVELOPMENT, INC.PERMIAN RESOURCES CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)



The following table provides additional information related to the Company’s lease assets and liabilities as presented on balance sheet for the periods presented:
(in thousands)Balance Sheet ClassificationJune 30, 2023December 31, 2022
Assets
Operating right-of-use assetsOperating lease right-of-use asset$62,049$64,792 
Finance right-of-use assetOther noncurrent assets15,267— 
Liabilities
Current
Operating lease liabilitiesOperating lease liabilities$36,160$29,759 
Finance lease liabilityOther current liabilities744— 
Noncurrent
Operating lease liabilitiesOperating lease liabilities$27,894$41,341 
Finance lease liabilityOther noncurrent liabilities14,690— 
retrospective application using either
There have been no other significant changes in leases during the six months ended June 30, 2023. Refer to Note 16—Leases in the notes to the consolidated financial statements in Part II, Item 8 of the following methodologies: (i) restatementCompany’s 2022 Annual Report.
Income Taxes
The Company is subject to U.S. federal, state and local income taxes with respect to its allocable share of each prior reporting period presentedany taxable income or (ii) recognitionloss of a cumulative-effect adjustmentOpCo, as well as any stand-alone income or loss generated by the Company. As of the date of initial application.
The Company doesthe Merger, OpCo is treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, OpCo is not expect netsubject to U.S. federal and certain state and local income taxes. Any taxable income or cash flowsloss generated by OpCo is passed through to be materially impacted byand included in the new standard, however,taxable income or loss of its members, including the Company, is currently analyzing whether changes to total revenues and total expenses will be necessary to properly reflect revenue for certain pipeline gathering, transportation and gas processing agreements. The Company continues to evaluate the expected disclosure requirements, changes to relevant business practices, accounting policies and control activities ason a result of the adoption of the ASU and has not yet developed estimates of the quantitative impactpro rata basis. Prior to the Company's consolidated financial statements. The Company has selected the modified retrospective method and will adopt this guidance on the effective date of January 1, 2018.
Note 2—Property Acquisitions
2017 Acquisition
On June 8, 2017, the Company completed the GMT Acquisition and acquired interests in 36 producing horizontal wells plus undeveloped acreage on approximately 11,850 net acres (14,770 gross acres) in Lea County, New Mexico for an unadjusted purchase price of $350.0 million. The Company operates approximately 79% of, and has an approximate 85% average working interest in, this acreage. The acquired acres are located in the Northern Delaware Basin with drilling locations in the Avalon Shale, 2nd Bone Spring Sand, 3rd Bone Spring Sand and Wolfcamp A formations.
The GMT AcquisitionMerger, OpCo was recorded as an asset acquisition under ASU 2017-01. Accordingly, the GMT purchase consideration has been allocated to the GMT oil and natural gas properties based on their relative fair values measured as of the acquisition date. After settlement statement adjustments of $0.9 million, the Company paid a net purchase price of $349.1 million. On a relative fair value basis, $296.2 million was allocated to unproved properties and $53.2 million to proved properties with the remaining purchase price allocated amongst other assets and liabilities. Transaction costs as they relate to the GMT Acquisition mainly consist of advisory, legal and accounting fees and are capitalized as incurred, and the Company has incurred $0.5 million in transaction costs related to this acquisition as of September 30, 2017.
2016 Acquisition
On December 28, 2016, the Company acquired interests in 31 producing horizontal wells plus undeveloped acreage on approximately 35,500 net acres (43,500 gross acres) in Reeves County, Texas for an unadjusted purchase price of $855.0 million, which consisted of cash consideration paidfully owned by the Company and a $32.3 million payable at December 31, 2016 thatall income and loss was settled in 2017 when title issues relatingtaxable.
Income tax expense recognized during interim periods is based on applying an estimated annual effective income tax rate to the purchased acreage were satisfied.Company’s year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The Company operates approximately 90%computation of the annual estimated effective tax rate at each interim period requires certain estimates and has an approximate 90% working interestsignificant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in this acreage. The Wolfcamp Avarious state jurisdictions, permanent and Wolfcamp B are producing horizons on this acreage,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—Acquisitions and Divestitures
Colgate Merger
On September 1, 2022, the Company believes that this acreage may be prospective forcompleted its merger (the “Merger”) with Colgate Energy Partners III, LLC (“Colgate”). Colgate was an independent oil and gas exploration and development company with properties located in the Wolfcamp C, Avalon and Bone Spring shale formations.
The Silverback Acquisition was recorded usingDelaware Basin. Refer to Note 2—Business Combination footnote in the acquisition method of accounting for business combinations. The allocationnotes to the consolidated financial statements in Part II, Item 8 of the purchase price is based upon management’s estimates and assumptions related toCompany’s 2022 Annual Report for additional details regarding the Merger.
Purchase Price Allocation
As of the date of this filing, the fair value of assets acquired and liabilities assumedon are not complete and adjustments may be made. The Company expects to complete the acquisitionpurchase price allocation during the 12-month period subsequent to the Merger closing date. There were no adjustments to the purchase price allocation during the six months ended June 30, 2023.
Supplemental Unaudited Pro Forma Financial Information
The results of Colgate’s operations have been included in the Company’s consolidated financial statements since September 1, 2022, the effective date using currently available information. Transaction costs relating to this purchase were expensed as incurred.of the Merger. The initial accountingfollowing supplemental unaudited pro forma financial information (“pro forma information”) for the Silverback Acquisition is preliminary,three and adjustments to provisional amounts (such as certain accrued liabilities) or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about facts and circumstances that existed assix months ended June 30, 2022 has been prepared from the respective historical consolidated financial statements of the acquisition date. SinceCompany and Colgate and has been adjusted to reflect the acquisition date,Merger as if it had occurred on January 1, 2022. The pro forma information reflects transaction accounting adjustments that the Company has recorded adjustmentsbelieves are factually supportable and that are expected to provisional amounts totaling $0.3 million. These adjustments did not have a materialcontinuing impact on the Company’s previously reported consolidated financial statements, and thereforeresults of operations, with the exception of certain nonrecurring items incurred in connection with the Merger. The pro forma information does not include any cost savings or other synergies that may result from the Merger or any estimated costs that will be incurred by the Company has not retrospectively adjusted those financial statements.to integrate the Colgate assets.
The table below summarizes the allocation of the $867.8 million adjusted purchase price, based on the acquisition date fair value of the assets acquired and the liabilities assumed as of September 30, 2017:
(in thousands)Silverback Acquisition
Purchase price$867,772
Allocation of purchase price: 
Unproved properties753,763
Proved properties116,700
Other property and equipment56
Liabilities(2,747)
Total$867,772

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CENTENNIAL RESOURCE DEVELOPMENT, INC.PERMIAN RESOURCES CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)



The pro forma effectsinformation is not necessarily indicative of the Silverbackresults that might have occurred had the Merger occurred in the past and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma information.
Three Months Ended June 30, 2022Six Months Ended June 30, 2022
Total Revenue$922,701 $1,612,855 
Net Income (loss)183,872 108,462 
Earnings (loss) per share:
Basic$0.65 $0.38 
Diluted0.58 0.35 
2023 Acquisition were insignificant
On February 16, 2023, the Company completed the acquisition of approximately 4,000 net leasehold acres and 3,300 net royalty acres for an unadjusted purchase price of $98 million. The acquired assets consist largely of undeveloped acreage that is contiguous to one of the Company’s existing core acreage blocks in Lea County, New Mexico.
The acquisition was recorded as an asset acquisition in accordance with Accounting Standards Codification (“ASC”) Topic 805, Business Combinations. Total consideration paid was $107.3 million after settlement statement adjustments, of which $61.8 million was allocated to unproved properties and $60.5 million to proved properties on a relative fair value basis, $9.8 million to net working capital (including $11.3 million in cash acquired), less a deferred tax liability assumed of $24.8 million. As of June 30, 2023, the Company incurred $1.6 million in direct transaction costs related to this purchase that have been capitalized as acquisition costs.
2023 Divestiture
On March 13, 2023, the Company completed the sale of its operated saltwater disposal wells and the associated produced water infrastructure in Reeves County, Texas. The total cash consideration received at closing was $125 million of which $65 million was directly related to the sale and transfer of control of its water assets, while the remaining $60 million consisted of contingent consideration that is tied to the Company’s 2016 resultsfuture drilling, completion and water connection activity in Reeves County, Texas, which will require repayment if certain performance obligations through September 2026 are not met. This portion of operations.the sale consideration that is tied to future performance has been recorded as a liability within the Company’s consolidated balance sheet. There was no gain or loss recognized as a result of this divestiture.
Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
(in thousands)June 30, 2023December 31, 2022
Accrued oil and gas sales receivable, net$167,458 $206,266 
Joint interest billings, net126,513 58,375 
Accrued derivative settlements receivable13,557 16,999 
Other2,096 1,206 
Accounts receivable, net$309,624 $282,846 
15
(in thousands)September 30, 2017 December 31, 2016
Accrued oil and gas sales receivable$32,294
 $11,596
Joint interest billings16,989
 2,942
Hedge settlements126
 194
Other798
 2
Accounts receivable, net$50,207
 $14,734
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PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Accounts payable and accrued expenses are comprised of the following:
(in thousands)June 30, 2023December 31, 2022
Accounts payable$102,531 $51,443 
Accrued capital expenditures178,213 133,854
Revenues payable275,873 250,120
Accrued employee compensation and benefits10,692 33,897
Accrued interest45,376 45,627
Accrued derivative settlements payable— 2,342
Accrued expenses and other49,063 44,873
Accounts payable and accrued expenses$661,748 $562,156 
(in thousands)September 30, 2017 December 31, 2016
Accounts payable$35,132
 $11,210
Accrued capital expenditures71,808
 24,038
Revenues payable16,534
 3,815
Payable to Silverback—
 32,293
Accrued underwriting fees—
 7,719
Other13,021
 7,025
Accounts payable and accrued expenses$136,495
 $86,100
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, 2023December 31, 2022
Credit Facility due 2027$300,000 $385,000 
Senior Notes
5.375% Senior Notes due 2026289,448 289,448 
7.75% Senior Notes due 2026300,000 300,000 
6.875% Senior Notes due 2027356,351 356,351 
3.25% Convertible Senior Notes due 2028170,000 170,000 
5.875% Senior Notes due 2029700,000 700,000 
Unamortized debt issuance costs on Senior Notes(9,804)(10,994)
Unamortized debt discount(45,925)(49,007)
Senior Notes, net1,760,070 1,755,798 
Total long-term debt, net$2,060,070 $2,140,798 
Credit Agreement
CRP,OpCo, the Company’s consolidated subsidiary, has a credit agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing in February 2027 (the “Credit Agreement”) that as of SeptemberJune 30, 2017,2023, had a borrowing base of $350.0 million, which has been committed by lenders$2.5 billion and is available for borrowing. A portionelected commitments of the revolving credit facility in an aggregate amount not to exceed $15.0 million may be used to issue letters of credit for the account of CRP or other designated subsidiaries of the Company.$1.5 billion. As of SeptemberJune 30, 2017,2023, the Company had $184.1$300 million of borrowings outstanding and $1.2 billion in available borrowing capacity, which was net of $165.0 million in borrowings and $0.9$5.8 million in letters of credit outstanding.
On April 24, 2023, the Company entered into the third amendment to the Credit Agreement (the “Third Amendment”). The Third Amendment, among other things, (i) reaffirmed the borrowing base at $2.5 billion and maintained the elected commitments at $1.5 billion; (ii) expanded the exceptions to the negative covenants to permit the incurrence of additional indebtedness on a pari passu basis with the facilities in the Credit Agreement, subject to certain conditions; and (iii) made technical changes to permit OpCo to potentially incur term loans in addition to the revolving loans provided under the Credit Agreement, subject to terms to be agreed with the lenders making such term loans and to the terms of the Credit Agreement.
The amount available to be borrowed under CRP's revolving credit facilitythe Credit Agreement is subjectequal to athe lesser of (i) the borrowing base, thatwhich is set at $2.5 billion; (ii) aggregate elected commitments, which is set at $1.5 billion; or (iii) $3.0 billion. The borrowing base is redetermined semi-annually each April 1in the spring and October 1fall by the lenders in their sole discretion. CRP's credit agreementIt also allows for two optional borrowing base redeterminations on January 1 and July 1.in between the scheduled redeterminations. The borrowing base depends on, among other things, the volumesquantities of CRP’sOpCo’s proved oil and natural gas reserves, estimated cash flows from thesethose reserves, and itsthe Company’s commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of permitted issued senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if actual borrowings in excess ofoutstanding exceed the revised borrowing capacity, are outstanding, CRPOpCo could be required to immediately repay a portion of its debt outstandingoutstanding. Borrowings under the Credit Agreement are guaranteed by certain of OpCo’s subsidiaries, including entities that became subsidiaries of OpCo through the Merger.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 175 to 275 basis points, depending on the percentage of elected commitments utilized, plus an additional 10 basis point credit agreement. In connection with the October 2017 semi-annual redetermination, on November 2, 2017, the Company entered into the fifth amendmentspread adjustment. Base rate loans bear interest at a rate per annum equal to the restated credit agreementgreatest 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 75 to increase175 basis points, depending on the percentage of the borrowing base from $350.0 millionutilized. OpCo also pays a commitment fee of 37.5 to $575.0 million.50 basis points on unused elected commitment amounts under its facility.
Interest and commitment fees are accrued based on a borrowing base utilization grid set forth in the credit agreement and are discussed in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” later in this report. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount and are included in interest expense in the consolidated statements of operations. The credit facility provides for interest only payments until October 15, 2019, when the credit agreement expires and all outstanding borrowings are due. The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-term debt as of September 30, 2017 (in thousands):
 2017 2018 2019 2020 2021
Long-term debt—
 —
 165,000
 —
 —
CRP’s credit agreementCredit Agreement contains restrictive covenants that limit itsour ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or declare dividends;redeem junior debt; (vi) enter into commodity hedges

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


exceeding a specified percentage of our expected production; (vii) enter into interest rate hedges exceeding a specified percentage of ourits outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates.
CRP’s credit agreementThe Credit Agreement also requires itOpCo to maintain compliance with the following financial ratios:
(i) a current ratio, which is the ratio of CRP’sOpCo’s consolidated current assets (including an add back of unused commitments under itsthe revolving credit facility and excluding non-cash derivative assets under FASB’s ASC Topic 815, Derivatives and Hedging (“ASC 815”), and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under our credit agreementthe Credit Agreement and non-cash liabilities under ASC 815)derivative liabilities), of not less than 1.0 to 1.0; and (2)
(ii) a leverage ratio, which isas defined within the Credit Agreement as the ratio of Total Funded Debt (as defined in CRP’s credit agreement)total funded debt to consolidated EBITDAX (as defined in CRP’s credit agreement)within the Credit Agreement) for the rolling four fiscalmost recent quarter period ending on such day,annualized, of not greater than 4.03.5 to 1.0.
CRPThe Credit Agreement includes fall away covenants, lower interest rates and reduced collateral requirements that OpCo may elect if OpCo is assigned an Investment Grade Rating (as defined within the Credit Agreement).
OpCo was in compliance with the covenants and the applicable financial ratios described above as of June 30, 2023.
Convertible Senior Notes
On March 19, 2021, OpCo 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, OpCo 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 OpCo 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The Convertible Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of OpCo’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. As of June 30, 2023, certain conditions have been met, and as a result, noteholders have the right to convert their Convertible Senior Notes during the third quarter of 2023.
OpCo can settle conversions by paying or delivering, as applicable, cash, shares of Class A Common Stock, or a combination of cash and shares of Class A Common Stock, at OpCo’s election. The initial conversion rate was 159.2610 shares of Class A Common Stock per $1,000 principal amount of Convertible Senior Notes, which represents an initial conversion price of approximately $6.28 per share of Class A Common Stock. The conversion rate and conversion price are subject to customary adjustments upon the occurrence of certain events (as defined in the indenture governing the Convertible Senior Notes) which, in certain circumstances, will increase the conversion rate for a specified period of time. As of June 30, 2023, the conversion rate was adjusted to 162.3827 shares of Class A Common Stock per $1,000 principal amount of Convertible Senior Notes as a result of cash dividends and distributions paid. 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 OpCo and are exchangeable into shares of the Company’s Class A Common Stock.
OpCo 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 Class A 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 OpCo sends the related redemption notice; and (ii) also on the trading day immediately before the date OpCo sends such notice.
If certain corporate events occur, including certain business combination transactions involving the Company or OpCo or a stock de-listing with respect to the Class A Common Stock, noteholders may require OpCo 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 as of 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, OpCo 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 Long-term debt, net in the consolidated balance sheets. As of June 30, 2023, the net liability related to the Convertible Senior Notes was $165.5 million.
Capped Called Transactions
In connection with the issuance of the Convertible Senior Notes in March 2021, OpCo 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 Class A Common Stock that initially underlie the Convertible Senior Notes and are expected to (i) generally reduce potential dilution to the Class A Common Stock upon a conversion of the Convertible Senior Notes, and/or; (ii) offset any cash payments OpCo 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 Class A Common Stock and an initial capped price of $8.4525 per share of Class A 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Senior Unsecured Notes
On September 1, 2022, in connection with the Merger, the Company entered into supplemental indentures whereby all of Colgate’s outstanding senior notes were assumed and became the senior unsecured debt of OpCo. The senior notes assumed by OpCo included $300 million of 7.75% senior notes due 2026 (the “2026 7.75% Senior Notes”) and $700 million of 5.875% senior notes due 2029 (the “2029 Senior Notes,”). The Company recorded the acquired senior notes at their fair values as of the Merger closing date, which were equal to 100% of par for the 2026 7.75% Senior Notes and 92.96% of par (a $49.3 million debt discount) for the 2029 Senior Notes. Interest on the 2026 7.75% Senior Notes is paid semi-annually each February 15 and August 15 and interest on the 2029 Senior Notes is paid semi-annually each January 1 and July 1.
On March 15, 2019, OpCo 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 OpCo 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 each April 1 and October 1.
On November 30, 2017, OpCo issued at par $400.0 million of 5.375% senior notes due 2026 (the “2026 5.375% Senior Notes” and throughcollectively with the filing2027 Senior Notes, the 2029 Senior Notes and the 2026 7.75% Senior Notes, the “Senior Unsecured Notes”) in a 144A private placement that resulted in net proceeds to OpCo of this report.$391.0 million, after deducting $9.0 million in debt issuance costs. Interest is payable on the 2026 5.375% Senior Notes semi-annually in arrears each January 15 and July 15.
In May 2020, $110.6 million aggregate principal amount of the 2026 5.375% 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, 2023, the remaining aggregate principal amount of 2027 Senior Notes and 2026 5.375% 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 OpCo’s current subsidiaries that guarantee OpCo’s Credit Agreement.
At any time prior to January 15, 2021 (for the 2026 5.375% Senior Notes), April 1, 2022 (for the 2027 Senior Notes), February 15, 2024 (for the 2026 7.75% Senior Notes), and July 1, 2024 (for the 2029 Senior Notes) (the “Optional Redemption Dates,”) OpCo may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of each 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 5.375% Senior Notes), 106.875% (for the 2027 Senior Notes), 107.750% (for the 2026 7.75% Senior Notes), and 105.875% (for the 2029 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, OpCo 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, OpCo 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 OpCo experiences certain defined changes of control (and, in some cases, followed by a ratings decline), each holder of the Senior Unsecured Notes may require OpCo 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 OpCo’s ability and the ability of OpCo’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. OpCo was in compliance with these covenants as of June 30, 2023.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Upon an Event of Default (as defined in the indentures governing the Senior Unsecured Notes), the trustee or the holders of at least 25% (or in the case of the 2026 7.75% Senior Notes and the 2029 Senior Notes, 30%) 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 OpCo, any restricted subsidiary of OpCo 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 the changes in the Company’s asset retirement obligations (“ARO”) associated with its working interests in oil and gas properties for the ninesix months ended SeptemberJune 30, 2017 (in thousands):2023:
Asset retirement obligations at January 1, 2017$7,226
Additional liabilities incurred1,813
Liabilities settled(65)
Accretion expense376
Revision to estimated cash flows(22)
Asset retirement obligations at September 30, 2017$9,328
(in thousands)
Asset retirement obligations, beginning of period$40,947 
Liabilities incurred1,207 
Liabilities acquired5,260 
Liabilities divested and settled(4,270)
Accretion expense1,402 
Asset retirement obligations, end of period$44,546 
ARO reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. Inherent in the fair value calculation of ARO are numerous estimates and assumptions, including plug and judgments including the ultimateabandonment settlement amounts, inflation factors, credit adjusted discount rates and timing of settlement. To the extent future revisions to these assumptions impact the value of the existing ARO liability,liabilities, a corresponding offsetting adjustment is made to the oil and natural 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
Long Term Incentive Plan
On October 7, 2016,May 23, 2023, the stockholders of the Company approved the Centennial Resource Development, Inc. 20162023 Long Term Incentive Plan (the “LTIP”). An aggregateThe LTIP is an equity incentive plan that replaced the Company’s prior plan, and, among other things, increased the number of 16,500,000 shares of Class A Common Stock were authorized for issuance under the LTIP,to employees and asdirectors by 25,000,000 shares to a total of September 30, 2017, the Company had 11,199,857 shares of Class A Common Stock available for future grants.69,250,000 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 restricted stock, dividend equivalents, restricted stock units and other stock or cash basedcash-based awards.
Stock-based compensation expense is recognized within both General and administrative expenses and Exploration expense onand other expenses in the consolidated statements of operations as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts. Upon adoption of ASU 2016-09 in October 2016, theoperations. The Company elected to accountaccounts for forfeitures of awards granted under these plansthe LTIP as they occur in determining compensation expense.occur.
20
(in thousands)For the Three Months Ended September 30, 2017 For the Nine Months Ended September 30, 2017
Restricted stock awards$1,490
 $3,364
Stock option awards2,104
 5,825
Performance stock units231
 231
Total stock-based compensation expense$3,825
 $9,420

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NOTES TO CONDENSED 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)2023202220232022
Equity Awards
Restricted stock$13,340 $4,481 $24,013 $7,920 
Stock option awards— 26 1 57 
Performance stock units22,354 2,079 29,551 4,082 
Other stock-based compensation expense(1)
— 71 — 143 
Total stock-based compensation - equity awards35,694 6,657 53,565 12,202 
Liability Awards
Performance stock units— (8,593)— 5,127 
Total stock-based compensation expense$35,694 $(1,936)$53,565 $17,329 
(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. As of January 1, 2023, the Company no longer offers the ESPP.
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 Class A 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”).
In connection with the Merger, the Compensation Committee of the Company’s Board of Directors (the “Compensation Committee”) approved a resolution to extend severance benefits under the Company’s Second Amended and Restated Severance Plan (the “Severance Plan”) to employees that experience a Qualifying Termination (as defined in the Severance Plan) following the Merger. As a result, affected employees of the Company will receive an accelerated vesting of their unvested restricted stock awards and PSUs upon termination, which will change the terms of the vesting conditions and will be treated as modifications in accordance with ASC 718. During the six months ended June 30, 2023, seventeen employees were terminated and received accelerated vesting of their unvested stock awards. These modifications resulted in an increase to total stock-based compensation expense for the three and six months ended June 30, 2023 of $25.9 million and $32.2 million as a result of the change in the fair value of the modified awards. The restricted stock shares and performance stock units that were accelerated are included within the vested line items in the below tables.
Restricted Stock
The following table provides information about restricted stock awards outstandingactivity during the ninesix months ended SeptemberJune 30, 2017:2023:
Restricted StockWeighted Average Fair Value
Awards Weighted Average Grant-Date Fair Value
Outstanding as of December 31, 2016256,597
 $20.03
Unvested balance as of December 31, 2022Unvested balance as of December 31, 20228,182,705 $6.03 
GrantedGranted731,782 9.79 
Vested—
 $—
Vested(2,577,919)9.04 
Granted841,443
 $17.21
Forfeited(8,788) $18.81
Forfeited(536,675)7.64 
Outstanding as of September 30, 20171,089,252
 $17.86
Unvested balance as of June 30, 2023Unvested balance as of June 30, 20235,799,893 6.73 
The Company grants service-based restricted stock awards to executivecertain officers and employees, which generally vesteither vests ratably over a three-year service period or cliff vests upon a five-year service period, and to directors, which generally vest over a one-year service period. Compensation cost for thethese service-based restricted stock awardsgrants is based uponon the grant-dateclosing market valueprice of the award. SuchCompany’s Class A 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, 2023 and 2022 was $23.3 million and $2.0 million, respectively. Unrecognized compensation cost related to unvested restricted shares at Septemberthat were unvested as of June 30, 20172023 was $15.7$29.9 million, which the Company expects to recognize over a weighted average period of 2.52.3 years.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Stock Options
Stock options that have been granted under the LTIP expire ten years from the grant date and have service-based vesting schedules of three years.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 Class A Common Stock as reported by NASDAQ on the date of grant.
grant date. Compensation cost related tofor stock options is based on the grant-date fair value of the award, which is then recognized ratably over the applicable vesting period. The Company estimates the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the re-levered asset volatility implied by a setperiod of comparable companies. Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.
The following table summarizes the assumptions and related information used to determine the grant-date fair value of stock options awarded during the nine months ended September 30, 2017:
 Nine Months Ended September 30, 2017
Weighted average grant-date fair value per share$7.15
Expected term (in years)6
Expected stock volatility38.1%
Dividend yield—%
Risk-free interest rate2.0%
three years.
The following table provides information about stock option awards outstanding during the ninesix months ended SeptemberJune 30, 2017:2023:
OptionsWeighted Average Exercise PriceWeighted Average Remaining Term
(in years)		Aggregate Intrinsic Value
(in thousands)
Outstanding as of December 31, 20222,056,467 $15.44 
Granted— — 
Exercised(46,834)4.98 $249 
Forfeited— — 
Expired(614,334)15.23 
Outstanding as of June 30, 20231,395,299 15.88 2.6$455 
Exercisable as of June 30, 20231,395,299 15.88 2.6$455 
 Options Weighted Average Exercise Price 
Weighted Average Remaining Term
(in years)
 
Aggregate Intrinsic Value
(in thousands)
Outstanding as of December 31, 20162,735,500
 $14.67
    
Exercised—
 $—
    
Granted1,550,000
 $17.96
    
Forfeited(268,000) $14.53
    
Outstanding as of September 30, 20174,017,500
 $15.95
 9.2
 $8,450
Exercisable as of September 30, 2017—
 $—
 —
 $—
The total fair value of stock options that vested was minimal during the six months ended June 30, 2023 and $0.2 million for the six months ended June 30, 2022. The intrinsic value of the stock options exercised was minimal for the six months ended June 30, 2023 and June 30, 2022. As of SeptemberJune 30, 2017,2023, there was $18.9 million ofno 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 2.2 years.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


options.
Performance Stock Units
The Company grants to executive officers performance stock units (“PSU”) to certain officers that are subject to market-based vesting criteria as well as a three-year service period.period ranging from three to five years. Vesting at the end of the three-year service period is subjectdepends on the Company’s absolute annualized total shareholder return (“TSR”) over the service period, as well as the Company’s TSR relative to the condition that our stock price increases by a greater percentage, or decreases by a lesser percentage, than the average percentage increase or decrease, respectively, of the stock pricesTSR of a peer group of companies. TheThese market-based conditions must be met in order for the stock awards to vest, and it is therefore possible that no shares could ultimately vest. However, the Company recognizes compensation expense for the performance stock unitsPSUs subject to market conditions regardless of whether it becomes probable that these conditions will be achievedmet or not, and compensation expense is not reversed if vesting does not actually occur.

The grant-dateCompany’s PSUs currently outstanding can be settled in either Class A Common Stock or cash upon vesting at the Company’s discretion. The Company intends to settle all PSUs in Class A Common Stock and has sufficient shares available under the LTIP to settle the units in Class A Common Stock at the potential future vesting dates. Accordingly, the PSUs have been treated as equity-based awards with their fair value wasvalues determined as of the grant or modification date, as applicable. The fair values of the awards are estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of our common stock,the Company’s Class A 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. periods.
The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awardedPSUs granted during the ninesix months ended SeptemberJune 30, 2017:
2023:
Nine Months Ended September 30, 20172023 Awards
Number of PSUs granted237,097
Weighted average fair value$16.68
Number of simulations1,000,000
10,000,000
Expected implied stock volatility41.6%59.2%
Dividend yield—%
Risk-free interest rate1.5%4.1%
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table provides information about performance stock unitsPSUs outstanding during the ninesix months ended SeptemberJune 30, 2017:2023:
AwardsWeighted Average Fair Value
Unvested balance as of December 31, 20227,638,098 $13.11 
Granted237,097 16.68 
Vested(1)
(1,624,895)9.74 
Forfeited(210,035)13.64 
Unvested balance as of June 30, 20236,040,265 13.71 
(1)     This balance includes vested PSU awards as of June 30, 2023 based on the original number of PSUs granted. Actual PSUs vested is based upon the Company’s absolute annualized TSR calculation at the time of vesting, which may be greater than or less than the original number granted.
 Awards Weighted Average Grant-Date Fair Value
Outstanding as of December 31, 2016—
 $—
Vested—
 $—
Granted193,391
 $21.53
Forfeited—
 $—
Outstanding as of September 30, 2017193,391
 $21.53
The total fair value of PSUs that vested during the six months ended June 30, 2023 was $32.0 million. As of SeptemberJune 30, 2017,2023, there was $3.9$56.7 million of unrecognized compensation cost related to PSUs that were unvested, performance stock units, which the Company expects to recognize on a pro ratapro-rata basis over a weighted average period of 2.752.7 years.

Liability Awards
18
The Company granted 5.5 million PSUs during third quarter of 2020 to certain executive officers that were settleable in cash and subject to market-based vesting criteria as well as a three-year service condition unless otherwise accelerated in accordance with the terms in the 2020 PSU agreement. As the PSUs were settleable in cash they were classified as liability awards in accordance with ASC 718 with the compensation cost for these liability awards being recorded based on their fair value as of each balance sheet date.
TableOn August 18, 2022, the Compensation Committee amended the 2020 PSU agreement to allow a portion of Contentsthe units to be settled in either cash or Class A Common Stock upon vesting at the Company’s discretion. The Company has the ability and currently intends to settle the 4.7 million 2020 PSUs that were modified in shares. As a result, these units were reclassified to equity based awards in accordance with ASC 718 and $10.0 million of incremental stock compensation expense was recognized during the third quarter of 2022 associated with the change in the fair value of the units.
CENTENNIAL RESOURCE DEVELOPMENT, INC.The remaining 0.8 million 2020 PSUs were accelerated vested and settled in a $9.4 million cash payment during the third quarter of 2022. There are no liability classified performance stock units outstanding as of June 30, 2023.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Note 7—Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations and usesmay use derivative instruments to manage its exposure to commodity price risk.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 usesuse 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 flowflows 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 opportunistically usesmay use commodity derivative instruments known as fixed price swaps to realize a known price for a specific volume of production.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 netresulting difference in the agreed upon published third-party index price (“index price”) and the swap fixed price multiplied by the contract volume. The Company also utilizes basis swaps contracts to hedge the difference between the index price and a local index price.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table summarizes the approximate volumes and average contract prices of swapderivative contracts the Company had in place as of SeptemberJune 30, 2017:
 Period Volume (Bbl) 
Weighted Average Fixed Price/Differential ($/Bbl) (1)
Crude oil swapsOctober 2017 - December 2017 170,200
 $50.41
 January 2018 - December 2018 36,500
 $55.95
Crude oil basis swapsOctober 2017 - November 2017 21,350
 $(0.20)
2023:
PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Crude Price
($/Bbl)(1)
Crude oil swapsJuly 2023 - September 20231,748,000 19,000 $85.04
October 2023 - December 20231,748,000 19,000 82.93
January 2024 - March 20241,547,000 17,000 77.14
April 2024 - June 20241,547,000 17,000 75.99
July 2024 - September 20241,564,000 17,000 74.89
October 2024 - December 20241,564,000 17,000 73.94
January 2025 - March 2025450,000 5,000 69.56
April 2025 - June 2025455,000 5,000 68.49
July 2025 - September 2025460,000 5,000 67.46
October 2025 - December 2025460,000 5,000 66.54
PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Collar Price Ranges
($/Bbl)(2)
Crude oil collarsJuly 2023 - September 2023644,000 7,000 $76.43-$92.70
October 2023 - December 2023644,000 7,000 76.43-92.70

PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(3)
Crude oil basis differential swapsJuly 2023 - September 20231,025,000 11,141 $0.63
October 2023 - December 20231,025,002 11,141 0.63
January 2024 - March 20241,092,000 12,000 0.66
April 2024 - June 20241,092,000 12,000 0.66
July 2024 - September 20241,104,000 12,000 0.66
October 2024 - December 20241,104,000 12,000 0.66
January 2025 - March 2025450,000 5,000 0.95
April 2025 - June 2025455,000 5,000 0.95
July 2025 - September 2025460,000 5,000 0.95
October 2025 - December 2025460,000 5,000 0.95

PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(4)
Crude oil roll differential swapsJuly 2023 - September 20231,656,000 18,000 $1.16
October 2023 - December 20231,656,000 18,000 1.16
January 2024 - March 20241,092,000 12,000 0.68
April 2024 - June 20241,092,000 12,000 0.67
July 2024 - September 20241,104,000 12,000 0.66
October 2024 - December 20241,104,000 12,000 0.66
January 2025 - March 2025180,000 2,000 0.37
April 2025 - June 2025182,000 2,000 0.37
July 2025 - September 2025184,000 2,000 0.37
October 2025 - December 2025184,000 2,000 0.37
(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.
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(Unaudited)

(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.

PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Gas Price
($/MMBtu)(1)
Natural gas swapsJuly 2023 - September 20231,486,925 16,162 $4.70
October 2023 - December 20231,413,628 15,366 4.90
January 2024 - March 20244,104,919 45,109 3.77
April 2024 - June 2024446,321 4,905 3.93
July 2024 - September 2024429,388 4,667 4.01
October 2024 - December 2024413,899 4,499 4.32

PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Differential
($/MMBtu)(2)
Natural gas basis differential swapsJuly 2023 - September 20236,210,000 67,500 $(1.30)
October 2023 - December 20236,210,000 67,500 (1.30)
January 2024 - March 20243,640,000 40,000 (0.52)
April 2024 - June 20241,820,000 20,000 (0.67)
July 2024 - September 20241,840,000 20,000 (0.66)
October 2024 - December 20241,840,000 20,000 (0.64)

PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Differential
($/MMBtu)(3)
Natural gas basis differential swapsJuly 2023 - September 20231,840,000 20,000 $(0.30)
October 2023 - December 20231,840,000 20,000 (0.30)
January 2024 - March 20242,730,000 30,000 (0.02)
PeriodVolume (MMBtu)Volume
(MMBtu/d)
Wtd. Avg. Collar Price Ranges
($/MMBtu)(4)
Natural gas collarsJuly 2023 - September 20236,563,075 71,338 $3.64-$7.52
October 2023 - December 20236,636,37272,134 3.66-8.22
January 2024 - March 20243,175,08134,891 3.36-9.44
April 2024 - June 20241,373,67915,095 3.00-6.45
July 2024 - September 20241,410,61215,333 3.00-6.52
October 2024 - December 20241,426,10115,501 3.25-7.30
(1)
The oil swap contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis swap contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period.
 Period Volume (MMBtu) 
Weighted Average Fixed Price/Differential ($/MMBtu) (1)
Natural gas swapsOctober 2017 - December 2017 368,000
 $2.94
Natural gas basis swapsJanuary 2018 - December 2018 1,825,000
 $(0.43)
 January 2019 - December 2019 1,825,000
 $(0.43)
(1)
The natural gas swap contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas. The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and the NYMEX price of Natural Gas during the relevant calculation period.
(1)    These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2)    These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas, during each applicable monthly settlement period.
(3)    These natural gas basis swap contracts are settled based on the difference between the Houston Ship Channel (“HSC”) price and the NYMEX price of natural gas, during each applicable monthly settlement period.
(4)    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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Derivative Instrument Reporting. The Company’s oil and natural gas derivative instruments have not been designated as hedges for accounting purposes; therefore,purposes. Therefore, all gains and losses are recognized in the Company’s condensed consolidated statements of operations. All derivative instruments are recorded at fair value in the condensed 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


The following table presents gains and losses forthe impact of the Company’s derivative instruments not designated as hedges for accounting purposesin its consolidated statements of operations for the periods presented:
Three Months Ended June 30,Six Months Ended June 30,
(in thousands)2023202220232022
Net gain (loss) on derivative instruments$20,601 $(34,134)$75,113 $(163,657)
 Successor  Predecessor  Successor  Predecessor
(in thousands)For the Three Months Ended September 30, 2017  For the Three Months Ended September 30, 2016  For the Nine Months Ended September 30, 2017  For the Nine Months Ended September 30, 2016
Net gain (loss) on derivative instruments$(896)  $1,741
  $5,392
  $(4,184)
Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives are measured at fair value and are included in the accompanying condensed 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 following tables below summarize the location and fair value amounts of alland the Company’s derivative instrumentsclassification 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 amounts offset in the condensed consolidated balance sheets:amounts:
 September 30, 2017
(in thousands)Balance Sheet Classification Gross Asset/Liability Amounts 
Gross Amounts Offset (1)
 Net Recognized Fair Value Assets/Liabilities
Derivative Assets       
Derivative instrumentsCurrent assets $562
 $(179) $383
Derivative instrumentsNoncurrent assets 246
 (4) 242
Total derivative assets  $808
 $(183) $625
Derivative Liabilities       
Derivative instrumentsCurrent liabilities $629
 $(179) $450
Derivative instrumentsNoncurrent Liabilities $4
 $(4) $—
Total derivative liabilities  $633
 $(183) $450
Balance Sheet ClassificationGross Fair Value Asset/Liability Amounts
Gross Amounts Offset(1)
Net Recognized Fair Value Assets/Liabilities
(in thousands)June 30, 2023
Derivative Assets
Commodity contractsDerivative instruments$103,121 $(15,384)$87,737 
Other noncurrent assets26,082 (2,805)23,277 
Derivative Liabilities
Commodity contractsDerivative instruments$15,738 $(15,384)$354 
Other noncurrent liabilities2,900 (2,805)95 
December 31, 2022
Derivative Assets
Commodity contractsDerivative instruments$125,120 $(24,323)$100,797 
Other noncurrent assets22,016 (3,691)18,325 
Derivative Liabilities
Commodity contractsDerivative instruments$26,321 $(24,323)$1,998 
Other noncurrent liabilities6,349 (3,691)2,658 
(1)
The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements or contract termination.
(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.
 December 31, 2016
(in thousands)Balance Sheet Classification Gross Asset/Liability Amounts 
Gross Amounts Offset (1)
 Net Recognized Fair Value Assets/Liabilities
Derivative Assets       
Derivative instrumentsCurrent assets $739
 $(308) $431
Total derivative assets  $739
 $(308) $431
Derivative Liabilities       
Derivative instrumentsCurrent liabilities $5,669
 $(308) $5,361
Derivative instrumentsNoncurrent Liabilities 20
 —
 20
Total derivative liabilities  $5,689
 $(308) $5,381
(1)
The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements or contract termination.
Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are primarily lenders under CRP’s credit agreement.OpCo’s Credit Agreement. The Company usesenters into new hedge arrangements only credit agreementwith participants to hedge with,under its Credit Agreement, since these institutions are secured equally with the holders of any CRPOpCo bank debt, which eliminates the potential need to post

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


collateral when Centennialthe Company is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.
In addition, the Company is exposed to credit risk associated with its derivative contracts from non-performance by its counterparties. The Company mitigates its exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of CRP’s credit facilitylender under OpCo’s Credit Agreement as referenced above.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 8—Fair Value Measurements
Recurring Fair Value Measurements
The Company follows FASB 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 is a listing of the Company’s netted asset or liability positions that have been measured at fair value and where they have been classifiedpresents, for each applicable level within the fair value hierarchy, as of September 30, 2017the Company’s net derivative assets and December 31, 2016:liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis:
(in thousands)Level 1 Level 2 Level 3
Commodity derivative asset (liability)     
September 30, 2017$—
 $175
 $—
December 31, 2016—
 (4,950) —
(in thousands)Level 1Level 2Level 3
June 30, 2023
Total assets$— $111,014 $— 
Total liabilities— 449 — 
December 31, 2022
Total assets$— $119,122 $— 
Total liabilities— 4,656 — 
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 judgementjudgment 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.
Oil and Gas Property Acquisitions. The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and natural gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgmentsjudgements and estimates by the Company’s management at the time of the valuation. Refer to Note 2—Property Acquisitions
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Impairment of Oil and Natural Gas Properties. The Company reviews its proved oil and natural gas properties for additional information onimpairment whenever events and circumstances indicate that the fair value of these assets acquired during 2016may be below their carrying value. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows from oil and 2017.gas properties is less than the carrying amount of the assets. In this circumstance, the Company then recognizes impairment expense for the amount by which the carrying amount of proved properties exceeds their estimated fair value. The Company reviews its oil and natural gas properties on a field-by-field basis.
The Company calculates the estimated fair value 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


calculation of ARO include pluggingthe estimated future costs to plug and abandon oil and gas properties and reserve lives. Refer to Note 5—Asset Retirement Obligationsfor 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 valuevalues 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, 2023December 31, 2022
Carrying ValuePrincipal AmountFair ValueCarrying ValuePrincipal AmountFair Value
Credit Facility due 2027(1)
$300,000 $300,000 $300,000 $385,000 $385,000 $385,000 
5.375% Senior Notes due 2026(2)
286,954 289,448 277,450 286,512 289,448 264,366 
7.75% Senior Notes due 2026(2)
300,000 300,000 302,663 300,000 300,000 291,338 
6.875% Senior Notes due 2027(2)
352,116 356,351 350,918 351,632 356,351 337,126 
3.25% Convertible Senior Notes due 2028(2)
165,457 170,000 321,804 165,025 170,000 285,858 
5.875% Senior Notes due 2029(2)
655,543 700,000 656,972 652,629 700,000 601,125 
(1)     The carrying values of the amounts outstanding under CRP’s credit agreementOpCo’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'Shareholders’ Equity and Noncontrolling Interest
Shareholders’ EquityStock Conversion
During the six months ended June 30, 2023, certain legacy owners of Colgate exchanged 21,917,000 of their units of OpCo (“Common Units”) and corresponding shares of Class C Common Stock for Class A Common Stock
On May 25, 2017, the Company’s stockholders approved the issuanceStock. A tax benefit of 26,100,000 shares$2.5 million was recorded in equity as a result of Class A Common Stock upon the conversion of 104,400 shares of Series B Preferred Stock that were held by affiliates of Riverstone, and there was nofrom the noncontrolling interest owner. No cash proceeds were received by the Company in connection with this issuance. The 104,400 sharesthe conversions.
Dividends
During the six months ended June 30, 2023, the Company declared a quarterly cash dividend of Series B Preferred$0.05 per share of Class A Common Stock were originally sold to affiliatesand a quarterly cash distribution of Riverstone in a private placement, whereby the proceeds from such issuance were used to fund a portion$0.05 per Common Unit (each of which has an underlying share of Class C Common Stock) for each of the first two quarters of 2023. Additionally, during the second quarter of 2023, the Company’s Board of Directors declared an initial variable cash considerationdividend of $0.05 per share of Class A Common Stock and a quarterly variable cash
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PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

distribution of $0.05 per Common Unit of OpCo. The cash dividends and distributions paid totaled $85.5 million for the six months ended June 30, 2023.
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 was approved to run through April 1, 2024. In connection with the Merger, the Repurchase Program was increased to $500 million and was extended through December 2016 Silverback Acquisition.
On May 4, 2017,31, 2024. The Repurchase Program can be used by the Company entered into subscription agreements with certain investors pursuant to which such investors agreed to purchase, in the aggregate, 23,500,000reduce its shares of Class A Common Stock and Class C Common Stock outstanding. Repurchases may be made from time to time in the open-market or via privately negotiated transactions at a purchase price of $14.50 per share, for gross proceeds of approximately $340.8 million. The closing under the subscription agreements occurred concurrentlyCompany’s discretion and will be subject to market conditions, applicable legal requirements, available liquidity, compliance with the closingCompany’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.
During the six months ended June 30, 2023, the Company paid $29.4 million to repurchase 2.8 million Common Units resulting in an equal number of the GMT Acquisition on June 8, 2017, and the proceeds were used to fund a majority of the purchase price of that acquisition.
Warrants
The Company’s Public Warrants were originally issued in connection with the IPO of Silver Run Acquisition Corporation. On March 1, 2017, the Company delivered a notice of redemption to all holders of its Public Warrants announcing its intention to redeem any Public Warrants that remained unexercised and outstanding after March 31, 2017 for $0.01 per Public Warrant. As of September 30, 2017, all of the Company’s Public Warrants have been either exercised forunderlying shares of Class AC Common Stock or redeemed for $0.01 per Public Warrant. As a result of all such Warrants exercised, the Company issued in aggregate 6,235,790 shares of Class A common stock to holders of Public Warrants.
As of September 30, 2017, 8,000,000 Private Placement Warrants remained outstanding. Private Placement Warrants are non-redeemable so long as they are held by the Company’s Sponsor or its permitted transferees. Each whole Private Placement Warrant is exercisable for one whole share of Class A Common Stock at a price of $11.50 per share. The warrants became exercisable on March 1, 2017 and will expire five years after the completion of the Business Combination or earlier upon redemption or liquidation.simultaneously being canceled.
Noncontrolling Interest
The noncontrolling interest relates to Common Units that were issued in CRPconnection with the Merger. At the date of the Merger, the noncontrolling interest represented approximately 48% of the ownership in OpCo. The noncontrolling interest percentage is representedaffected by 19.2 millionvarious equity transactions such as Common Unit and Class C Common Stock exchanges and Class A Common Stock activities.
As of June 30, 2023, the noncontrolling interest ownership of OpCo decreased to 43.4% from 48% as of December 31, 2022. The decrease was mainly the result of the exchange of Common Units (and corresponding shares of Class C Common Stock that were issued to the Centennial Contributors in connection with the Business Combination, and such shares continue to be held by holders other than the Company. As of September 30, 2017, the Company’s noncontrolling interest was 6.9%, which declined from 7.6% as of March 31, 2017, due to the issuance of 23.5 million shares ofStock) for Class A Common Stock on June 8, 2017. and the Class C Common Stock repurchase by the Company discussed above.
The Company has consolidatedconsolidates the financial position, and results of operations and cash flows of CRPOpCo and reflected thatreflects the portion retained by the other holders of Common Units as a noncontrolling interest. Refer to the consolidated statementstatements of shareholders’ equity for a summary of the activity attributable to the noncontrolling interest during the period.
Note 10—Income Taxes
CRP is treated as a partnership for U.S. federal and most applicable state and local income tax purposes, and the Company consolidates the financial results of CRP. As a partnership, CRP is not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by CRP is passed through to and included in the taxable income or loss of its members, including the Company, on a pro rata basis. The Company is subject to U.S. federal income taxes, in addition to state and local income taxes, with respect to its allocable share of any taxable income or loss of CRP, as well as any stand-alone income or loss generated by the Company.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to the Company’s year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provision for income taxes for the three and nine months ended September 30, 2017 and 2016 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to pre-tax income primarily because of state income taxes and estimated permanent differences.
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 jurisdictions, permanent and temporary differences and the likelihood of recovering deferred tax assets generated in the current year. The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained, additional information becomes known or as the tax environment changes.
Note 11—Earnings Per Share
Basic earnings per share (“EPS”) is calculated by dividing net income availableattributable to common shareholdersClass A Common stock by the weighted average shares of Class A Common Stock outstanding during each period. DilutiveDiluted EPS is calculated by dividing adjusted net income available to common shareholders by the weighted average numbershares of diluted common sharesClass A 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, and warrantswithholding amounts from the employee stock purchase plan (prior to its discontinuation in January 2023), all using the treasury stock method,method; (ii) equity-based restricted stock and (ii)performance stock units that were vested but not outstanding, using the treasury stock method; and (iii) the Company’s Class C common stockCommon Stock and potential shares issuable under our Convertible Senior Notes, both using the “if-converted” method, which is net of tax.
Shares
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Table of the Company’s unvested restricted stock and performance stock units are eligible to receive dividends; however, dividend rights will be forfeited if the award does not vest. Accordingly, these shares are not considered participating securities. Shares of the Company’s Class C Common Stock and warrants do not share in earnings or losses and are therefore not participating securities as well. In addition, the Company’s shares of Series B Preferred Stock were converted into shares of Class A Common Stock on May 25, 2017 as a result of shareholder vote. As such, the Company no longer has any participating securities and therefore does not utilize the two-class method.Contents
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table reflects the allocation of net income to common shareholders and EPS computations for the periods indicated based on a weighted average number of common stockClass A Common Stock outstanding for theeach period:
Three Months Ended June 30,Six Months Ended June 30,
(in thousands, except per share data)2023202220232022
Net income (loss) attributable to Class A Common Stock$73,399 $191,826 $175,519 $207,628 
Add: Interest on Convertible Senior Notes, net of tax1,376 1,306 2,750 2,611 
Adjusted net income (loss) attributable to Class A Common Stock$74,775 $193,132 $178,269 $210,239 
Basic weighted average shares of Class A Common Stock outstanding315,168 284,992 305,593 284,922 
Add: Dilutive effects of Convertible Senior Notes27,605 27,074 27,460 27,074 
Add: Dilutive effects of equity awards and ESPP shares9,142 8,038 10,882 7,897 
Diluted weighted average shares of Class A Common Stock outstanding351,915 320,104 343,935 319,893 
Basic net earnings (loss) per share of Class A Common Stock$0.23 $0.67 $0.57 $0.73 
Diluted net earnings (loss) per share of Class A Common Stock$0.21 $0.60 $0.52 $0.66 
(in thousands, except per share data)For the Three Months Ended September 30, 2017 For the Nine Months Ended September 30, 2017
Net income attributable to common shareholders$14,447
 $45,032
Add: Income from conversion of Class C Common Stock1,193
 3,196
Adjusted net income attributable to common shareholders15,640
 48,228
    
Basic net earnings per share$0.06
 $0.20
Diluted net earnings per share$0.06
 $0.19
    
Basic weighted average shares outstanding223,622
 227,557
Add: Dilutive effects of equity awards2,598
 4,481
Add: Dilutive effects of conversion19,156
 19,156
Diluted weighted average shares outstanding245,376
 251,194
For the three months ended September 30, 2017,The following table presents shares excluded from the diluted earnings per share calculation excludes 1.5 million stock options that were out-of-the-money, as there effect was anti-dilutive, and for the nine months ended September 30, 2017, the diluted earnings per share calculation excludes 1.0 million stock options that were out-of-the-money,periods presented as there effecttheir impact was anti-dilutive.anti-dilutive:

Three Months Ended June 30,Six Months Ended June 30,
(in thousands)2023202220232022
Out-of-the-money stock options1,416 2,049 1,665 2,073 
Weighted average shares of Class C Common Stock245,586 — 254,429 — 
Restricted stock208 — 104— 
Performance stock units116 — 58 224 


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CENTENNIAL RESOURCE DEVELOPMENT, INC.PERMIAN RESOURCES CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)



Note 12—11—Transactions with Related Parties
CustomerRiverstone Investment Group LLC (“Riverstone”), NGP Energy Capital (“NGP”), and Supplier Relationships
Riverstone Affiliated Companies. RiverstonePearl Energy Investments (“Pearl”) and its affiliates, including our Sponsor, beneficially own more than 10% of our equity interest and are therefore considered related parties. From time to time, the Company obtains services related to its drilling and completion activities from affiliates of Riverstone. In particular, the Company has paid the following amounts to the following affiliates of Riverstone for such services: (i) approximately $30.4 million and $70.6 million during the three and nine months ended September 30, 2017, respectively, to Liberty Oilfield Services, LLC; and (ii) approximately $1.7 million and $4.0 million during the three and nine months ended September 30, 2017, respectively, to Permian Tank and Manufacturing, Inc.
Other Affiliated Companies. Mark G. Papa, our President, Chief Executive Officer and Chairman of the Board, serves as a director and Chairman of the Board of Oil States International, Inc., an energy services company publicly traded on the New York Stock Exchange (“Oil States”). From time to time, the Company obtains services related to drilling and completion activities from Oil States. During the three and nine months ended September 30, 2017, the Company paid approximately $2.4 million and $6.4 million, respectively, to Oil States. At September 30, 2017, included in Accounts payable and accrued expenses on the consolidated balance sheets was $1.5 million due to Oil States.
NGP Affiliated Companies. Beginning December 28, 2016, NGP and entities affiliated with NGP were no longer considered related parties of the Company, and any expenses incurred on or after December 28, 2016 with NGP or its affiliates are no longer classified as related party expenses. However, expenses incurred before December 28, 2016 with NGP or its affiliates were classified as related party expenses as NGPeach entity each beneficially owned more than 10% of our equity interest. Such transactions are detailed below.
In May 2016,interest in the Company acquired undeveloped acreage in Reeves County, Texasas of June 30, 2023. Certain members of OpCo’s management owned profit interests at CEP III Holdings, LLC and anits affiliates (“Colgate Holdings”) until December 2022. Due to Riverstone, NGP, and Pearl’s beneficial ownership and NGP, Pearl and OpCo’s management’s previously held interest in an uncompleted horizontal wellbore for approximately $9.8 million from Caird DB,Colgate Holdings, these entities are considered related parties to the Company.
The Company has the following agreements in place that represent related party transactions. The Company believes that the terms of these arrangements are no less favorable to either party than those held with unaffiliated parties.
(i) A marketing agreement with Lucid Energy Delaware, LLC (“Lucid”), who was an affiliate of NGP. In addition,Riverstone until the Company paid approximately $3.3 million duringsale of Riverstone’s investment in Lucid in July 2022. As a result of such sale, there no longer remains a related party relationship with Lucid as of the nine months ended September 30, 2016 (Predecessor), to RockPile Energy Services, LLCthird quarter of 2022.
(ii) A vendor arrangement with Streamline Innovations Inc, (“Rockpile”Streamline”). On July 3, 2017, Rockpile who was acquired by an unrelated third party and is no longer an affiliate of NGP.Riverstone beginning in the second quarter of 2022 and an affiliate of Pearl.
(iii) A joint operating agreement with Maple Energy Holdings, LLC (“Maple”) who is an affiliate of Riverstone. On December 23, 2022, the Company sold all of its working interest ownership in producing properties operated by Maple for an unadjusted sales price of $60 million. As a result of such sale, there no longer remains a related party relationship with Maple as of December 31, 2022.
(iv) A vendor arrangement with LM Energy Partners who was an affiliate of Colgate Holdings until the sale of Colgate Holdings’ investment in LM Energy Partners in December 2022. As a result of such sale, there no longer remains a related party relationship with LM Energy Partners as of December 31, 2022.
The following table summarizes the costs incurred and revenues recognized from such arrangements during the periods they were considered related parties, as discussed above, as included in the consolidated statements of operations for the periods indicated, as well as the related net receivables and payables outstanding as of the balance sheet dates:
Three Months Ended June 30,Six Months Ended June 30,
(in thousands)2023202220232022
Lucid
Oil and gas sales$— $9,107 $— $18,590 
Gathering, processing and transportation expenses— 2,150 — 4,669 
Streamline
Lease operating expenses1,238 — 1,834 — 
(in thousands)June 30, 2023December 31, 2022
Accounts receivable, net
Maple— 128 
Accounts payable and accrued expenses
Maple— 2,790 
LM Energy Partners— 2,283 
During the six months ended June 30, 2023, the Company repurchased 2.8 million shares of Class C Common Stock from NGP for $29.4 million under the Repurchase Program. The shares that were repurchased from NGP were subsequently canceled by the Company.
Note 13—12—Commitments and Contingencies
Commitments
In June 2017, the Company entered into a transportation service agreement whereby it is required to deliver 40,000 MMBtu per day for a term of one year, and this delivery commitment is tied to the Company’s natural gas production in Reeves and Ward counties, Texas.
The Company routinely enters into, extends or extendsamends operating agreements office and equipment leases, drilling and completion rig contracts, among others, in the ordinary course of business. Other than the above,ground lease agreement the Company entered into during the six months ended June 30, 2023, discussed in Note 1—Basis of Presentation and Summary of Significant Accounting Policies, there have been no other material, non-routine changes in commitments during the ninesix months ended SeptemberJune 30, 2017.2023. Please refer to Note 13—Commitment14—Commitments and Contingencies included in Part II, Item 8.8 in our 2016the Company’s 2022 Annual Report.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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. Management
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 operators, including upstream producers like the Company, 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, which may be subject to additional interest charges, 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 the reserve of a contingent liability to be recognized as of the date of these condensed 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,
202320222023

2022
Operating revenues (in thousands):
Oil sales$549,226 $349,591 $1,073,612 $612,358 
Natural gas sales(1)
23,647 68,030 55,769 107,048 
NGL sales(2)
50,525 55,033 110,285 100,525 
Oil and gas sales$623,398 $472,654 $1,239,666 $819,931 
(1)    Natural gas sales include a portion of gathering, processing and transportation expenses (“GP&T”), that are reflected as a reduction to natural gas sales of $7.4 million and $18.7 million for the three and six months ended June 30, 2023 and none for the three and six months ended June 30, 2022.
(2)    NGL sales include a portion of GP&T, that are reflected as a reduction to NGL sales of $16.5 million and $32.6 million for the three and six months ended June 30, 2023 and none for the three and six months ended June 30, 2022.
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.
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PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 agreed upon delivery point at which the purchaser takes title of the product. The midstream processing entity gathers and processes the raw gas and then remits proceeds to the Company. For these contracts, the Company evaluates when control is transferred and revenue should be recognized. Where the Company elects to take its residue gas or NGL product “in-kind” at the plant tailgate, fees incurred prior to transfer of control are presented as GP&T within the consolidated statements of operations. Where the Company does not take its residue gas or NGL products “in-kind”, transfer of control occurs at the inlet of the gas gathering systems, or prior, and fees incurred subsequent to this point are reflected as a net reduction to natural gas and NGL sales revenues presented in the table above. During the six months ended June 30, 2023, the majority of the Company’s contracts with customers have elections to not take its products “in-kind” resulting in more fees being shown as a net reduction to revenues as discussed above.
Performance obligations
For all commodity products, the Company records revenue in the month production is delivered to the purchaser. Settlement statements for crude oil are generally received within 30 days following the date that production volumes are delivered, but for natural gas and NGL sales, statements may not be received for 30 to 60 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, 2023 and December 31, 2022, such receivable balances were $167.5 million and $206.3 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 six months ended June 30, 2023 and 2022, 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

Dividends Declared
Credit Facility Amendment

In connection with the October 2017 semi-annual redetermination, on NovemberOn August 2, 2017,2023, the Company entered intoannounced that its Board of Directors declared a quarterly cash dividend of $0.05 per share of Class A Common Stock and a quarterly cash distribution of $0.05 per Common Unit of OpCo. Additionally, the fifth amendmentCompany’s Board of Directors declared a variable cash dividend of $0.05 per share of Class A Common Stock and a quarterly variable cash distribution of $0.05 per Common Unit of OpCo. The base and variable dividend represent a total return of $0.10 per share. The dividends are payable on August 23, 2023 to the restated credit agreement to increase the borrowing base from $350.0 million to $575.0 million.shareholders of record as of August 15, 2023.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationOperations
The following discussion and analysis of our financial condition and results of operationoperations should be read in conjunction with the accompanying condensed 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 implementation and actual result of the Merger (defined below) and other uncertainties, as well as those factors discussed above in “Cautionary Statement RegardingConcerning Forward-Looking Statements” and in our 2016 Annual Report under the heading “Item 1A. Risk Factors,”Factors” in this Quarterly Report and our 2022 Annual Report; all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may or may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Overview
We arePermian Resources Corporation is an independent oil and natural gas company focused on the responsible acquisition, optimization and development of unconventionalhigh-return oil and associated liquids-rich natural gas reserves in the Permian Basin.properties. Our assets are concentratedlocated in the Delaware Basin, a sub-basincore of the PermianDelaware Basin. Our capital programsprincipal 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 “Permian Resources,” “we,” “us,” or “our” are specifically focusedto Permian Resources Corporation and its consolidated subsidiary, Permian Resources Operating, LLC (“OpCo”).
On September 1, 2022, we completed the merger (the “Merger”) with Colgate Energy Partners III, LLC (“Colgate”). Colgate’s results of operations were included in the Company’s financial statements and results of operations beginning on projects that we believe provide the greatest potential for repeatable success and production growth.September 1, 2022.
Market Conditions
Our revenue, profitability and ability to return cash to stockholders can depend substantially on factors beyond our control, such as economic, political and regulatory developments. Prices for crude oil, natural gas and NGLs have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future.
Growth of global oil supply has been limited by production curtailment agreements among the Organization of Petroleum Exporting Countries and other oil producing countries (“OPEC+”) and overall reduced drilling and completion activity from U.S. producers compared to prior pre-pandemic levels. Meanwhile, demand for oil and gas has risen steadily post-pandemic and has been positively impacted by a global-wide transition away from coal to natural gas. The aforementioned factors, among others, led to heightened commodity prices during certain time periods of 2022, particularly during the beginning of Russia’s invasion of Ukraine. Specifically, NYMEX WTI spot prices for crude oil reached a high of $123.70 per barrel on March 8, 2022 and the NYMEX Henry Hub index price for natural gas reached a high of $9.85 per MMBtu on August 23, 2022. During this time, governments from several countries coordinated a simultaneous release of a portion of their strategic petroleum reserves, which increased global oil inventories to near normalized levels. As such, crude oil prices have fallen since their peak in mid-2022 due in part to these actions, in addition to global recession concerns, a high interest rate environment and lower than expected demand from China. The U.S. domestic environment and geopolitical events such as those discussed above may cause oil and gas prices to fluctuate significantly in the future.
The oil and natural gas industry is cyclical, and commodity prices can be volatile. In the second half of 2014, oil prices began a rapid and significant decline as global and domestic supply began to outpace demand. During 2015 and through 2016, global and domestic oil supply continued to outpace demand resulting in further deterioration in realized oil prices. Thus far into 2017, commodity prices have been volatile, and it is likely that commodity prices, as well as commodity price differentials, will continue to fluctuatebe volatile due to fluctuations in global supply and demand, inventory supply levels, geopolitical events, federal and state government regulations, weather conditions, geopoliticalthe 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 2015:2021:
 2015 2016 2017
 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3
Crude oil (per Bbl)$48.62
 $57.84
 $46.60
 $42.16
 $33.59
 $45.70
 $45.00
 $49.27
 $51.82
 $48.32
 $48.17
Natural gas (per MMBtu)$2.81
 $2.74
 $2.73
 $2.24
 $1.98
 $2.25
 $2.80
 $3.17
 $3.06
 $3.14
 $2.95
Although oil and natural gas prices have begun to recover from the lows experienced during the first quarter of 2016, forecast prices for both oil and natural gas have not rebounded to 2014 levels. A sustained drop in oil, natural gas and NGL prices may not only decrease our revenues on a per unit basis but may also reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore potentially lower our oil, natural gas and NGL reserve quantities.
202120222023
Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2
Crude oil (per Bbl)$57.84 $66.06 $70.56 $77.09 $94.40 $108.34 $91.56 $82.64 $76.13 $73.78 
Natural gas (per MMBtu)$3.44 $2.88 $4.28 $4.74 $4.60 $7.39 $7.96 $5.55 $2.67 $2.12 
Lower commodity prices in the future couldand 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 future business,operating cash flows, liquidity, financial condition, results of operations, operating cash flows, liquidity future business and operations, and/or our ability to finance planned capital expenditures.
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expenditures, which could in turn impact our ability to comply with covenants under our five-year secured revolving credit facility (the “Credit Agreement”) and senior notes. Lower commodityrealized prices may also reduce the borrowing base under CRP’s credit agreement,OpCo’s Credit Agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under the credit agreement. Alternatively, higherCredit Agreement.
Due to the cyclical nature of the oil and natural gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, costs of oilfield goods and services generally also increase; however, 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 2022 and 2023. These inflationary pressures may also result in significant non-cash fair value losses being incurred onincreases to the costs of our derivatives,oilfield goods, services and personnel, which couldcan in turn cause usour capital expenditures and operating costs to experience net losses when oil and natural gas prices rise.
20172023 Highlights and Future Considerations
Operational Highlights2023 Acquisition
We operated a six rig program, which allowed us to spud 22 operated wells and complete 13 operated wells during the third quarter. Over half of theOn February 16, 2023, we completed wells were put on production during September, and the total completed wells during the quarter had an average effective lateral lengthacquisition of approximately 5,800 feet.

Acquisition Highlights
On June 8, 2017, we completed the GMT Acquisition, which consisted of interests in 36 producing horizontal wells plus approximately 11,850 undeveloped4,000 net leasehold acres in the core of the Northern Delaware Basin in Lea County, New Mexicoand 3,300 net royalty acres for an unadjusted purchase price of $350.0$98 million.
Financing Highlights
In connection with the GMT Acquisition, in June 2017, we issued and sold in a private placement 23,500,000 shares The acquired assets consist largely of undeveloped acreage that is contiguous to one of our Class A Common Stockexisting core acreage blocks in Lea County, New Mexico.
2023 Divestiture
On March 13, 2023, we completed the sale of our operated saltwater disposal wells and the associated produced water infrastructure in Reeves County, Texas. The total cash consideration received at closing was $125 million, of which $65 million was directly related to certain institutional investors, which resultedthe sale and transfer of control of our water assets, while the remaining $60 million consisted of contingent consideration that is tied to our future drilling, completion and water connection activity in grossReeves County, Texas. The proceeds of approximately $340.8 million, and such proceedsfrom the divestiture were used to fund the majoritybolt-on acquisition discussed above and pay down additional borrowings under our credit facility.
Shareholder Returns
During the six months ended June 30, 2023, we declared a quarterly cash dividend of $0.05 per share of Class A Common Stock and a quarterly cash distribution of $0.05 per common unit of OpCo (“Common Unit”, each of which has an underlying share of Class C Common Stock) for each of the acquisition purchase price.first two quarters of 2023. Additionally, during the second quarter of 2023, our Board of Directors declared an initial variable cash dividend of $0.05 per share of Class A Common Stock and a variable cash distribution of $0.05 per Common Unit of OpCo. The cash dividends and distributions paid totaled $85.5 million for the six months ended June 30, 2023.
In connection withDuring the October 2017 semi-annual redetermination, on November 2, 2017,six months ended June 30, 2023, we paid $29.4 million to repurchase 2.8 million Common Units resulting in an equal number of the Companyunderlying shares of Class C Common Stock simultaneously being canceled.
Financing
On April 24, 2023, we entered into the fifththird amendment (the “Third Amendment”) to the restated credit agreement to increaseThird Amended and Restated Credit Agreement. The Third Amendment, among other things, (i) reaffirmed the borrowing base from $350.0 millionat $2.5 billion and maintained the elected commitments at $1.5 billion; (ii) expanded the exceptions to $575.0 million.the negative covenants to permit the incurrence of additional indebtedness on a pari passu basis with the facilities in the Credit Agreement, subject to certain conditions; and (iii) made technical changes to permit OpCo to potentially incur term loans in addition to the revolving loans provided under the Credit Agreement, subject to terms to be agreed with the lenders making such term loans and to the terms of the Credit Agreement.

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Results of Operations
On October 11, 2016, we consummated the acquisition of approximately 89% of the outstanding membership interests in CRP (the “Business Combination”). Our financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. We are the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination. Except as the context otherwise requires, references in the following discussion to the "Company," "we," "our" or "us" with respect to periods prior to the closing of the Business Combination are to CRP and its operations before the Business Combination.
Three Months Ended SeptemberJune 30, 2017 (Successor)2023 Compared to Three Months Ended SeptemberJune 30, 2016 (Predecessor)2022
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:
 Successor  Predecessor Increase/(Decrease)
 For the Three Months Ended September 30, 2017  For the Three Months Ended September 30, 2016 $ %
Net revenues (in thousands):        
Oil sales$87,286
  $23,388
 $63,898
 273 %
Natural gas sales12,852
  2,629
 10,223
 389 %
NGL sales11,473
  1,304
 10,169
 780 %
Total net revenues$111,611
  $27,321
 $84,290
 309 %
         
Average sales prices:        
Oil (per Bbl)$44.95
  $41.69
 $3.26
 8 %
Effect of derivative settlements on average price (per Bbl)0.21
  12.36
 (12.15) (98)%
Oil net of hedging (per Bbl)$45.16
  $54.05
 $(8.89) (16)%
         
Average NYMEX price for oil (per Bbl)$48.17
  $45.00
 $3.17
 7 %
         
Natural gas (per Mcf)$2.72
  $2.67
 $0.05
 2 %
Effect of derivative settlements on average price (per Mcf)—
  —
 —
 — %
Natural gas net of hedging (per Mcf)$2.72
  $2.67
 $0.05
 2 %
         
Average NYMEX price for natural gas (per Mcf)$2.95
  $2.80
 $0.15
 5 %
         
NGL (per Bbl)$24.83
  $14.02
 $10.81
 77 %
         
Net production:        
Oil (MBbls)1,942
  561
 1,381
 246 %
Natural gas (MMcf)4,733
  984
 3,749
 381 %
NGL (MBbls)462
  93
 369
 397 %
Total (MBoe) (1)
3,192
  818
 2,374
 290 %
         
Average daily net production volume:        
Oil (Bbls/d)21,108
  6,098
 15,010
 246 %
Natural gas (Mcf/d)51,444
  10,695
 40,749
 381 %
NGL (Bbls/d)5,018
  1,011
 4,007
 396 %
Total (Boe/d) (1)
34,700
  8,891
 25,809
 290 %
Three Months Ended June 30,Increase/(Decrease)
20232022$%
Net revenues (in thousands):
Oil sales$549,226 $349,591 $199,635 57 %
Natural gas sales(1)
23,647 68,030 (44,383)(65)%
NGL sales(2)
50,525 55,033 (4,508)(8)%
Oil and gas sales$623,398 $472,654 $150,744 32 %
Average sales prices:
Oil (per Bbl)$71.52 $104.69 $(33.17)(32)%
Effect of derivative settlements on average price (per Bbl)3.42 (16.97)20.39 120 %
Oil including the effects of hedging (per Bbl)$74.94 $87.72 $(12.78)(15)%
Average NYMEX WTI price for oil (per Bbl)$73.78 $108.34 $(34.56)(32)%
Oil differential from NYMEX(2.26)(3.65)1.39 38 %
Natural gas price excluding the effects of GP&T (per Mcf)(1)
$1.24 $6.22 $(4.98)(80)%
Effect of derivative settlements on average price (per Mcf)0.52 (1.55)2.07 134 %
Natural gas including the effects of hedging (per Mcf)$1.76 $4.67 $(2.91)(62)%
Average NYMEX Henry Hub price for natural gas (per MMBtu)$2.12 $7.39 $(5.27)(71)%
Natural gas differential from NYMEX(0.88)(1.17)0.29 25 %
NGL price excluding the effects of GP&T (per Bbl)(2)
$20.73 $44.77 $(24.04)(54)%
Net production:
Oil (MBbls)7,680 3,339 4,341 130 %
Natural gas (MMcf)25,092 10,941 14,151 129 %
NGL (MBbls)3,231 1,230 2,001 163 %
Total (MBoe)(3)
15,093 6,392 8,701 136 %
Average daily net production:
Oil (Bbls/d)84,393 36,696 47,697 130 %
Natural gas (Mcf/d)275,734 120,225 155,509 129 %
NGL (Bbls/d)35,502 13,507 21,995 163 %
Total (Boe/d)(3)
165,850 70,240 95,610 136 %
(1)
Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

(1)    Natural gas sales for the three months ended June 30, 2023 include $7.4 million of gathering, processing and transportation expenses (“GP&T”) that are reflected as a reduction to natural gas sales and zero for the three months ended June 30, 2022. Natural gas average sales price, however, excludes $0.30 per Mcf of these GP&T charges for the three months ended June 30, 2023.
(2)    NGL sales for the three months ended June 30, 2023 include $16.5 million of GP&T that are reflected as a reduction to NGL sales and zero for the three months ended June 30, 2022. NGL average sales price, however, excludes $5.09 per Bbl of these GP&T charges for the three months ended June 30, 2023.
(3)    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. Our totalTotal net revenues for the three months ended SeptemberJune 30, 2017 (Successor)2023 were $84.3$150.7 million (or 309%32%) higher than total net revenues for the three months ended SeptemberJune 30, 2016 (Predecessor). Our revenues2022. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Our netNet production volumes for oil, natural gas and NGLs increased 246%130%, 381%129% and 397%163%, respectively, between periods. The increase in oil volume increase between periodsproduction resulted primarily from our drilling success inplacing 140 wells online since the Delaware Basin,second quarter of 2022 as well ascompared to 50 wells brought online since the producing properties wesecond quarter of 2021. Oil production also benefited from wells acquired in the Silverback and GMT Acquisitions, which collectively added 232 MBbls of net oil production to our third quarter 2017 results. Since the third quarter of 2016, we placed 49 operated wells on production in the Delaware Basin,Merger with Colgate, which added 1,4161,663 MBbls of net oil production to the third quarter of 2017. The increase in our operated well count is attributable to the ramp up of our drilling program starting in the fourth quarter of 2016.three months ended June 30, 2023. These oil volume increases were partially offset by normal production declinesdecline across our existing wells. Our naturalNatural gas and NGLs are produced concurrently with our crude oil volumes, resultingwhich typically results in a high correlation between fluctuations in our oil quantities sold and our natural gas and NGL quantities sold. Naturalsold, driving the 129% and 163% respective increases in gas and NGL volumes between periods.
These increases were also impactedpartially offset by the acreage we acquired from Silverback, which has a higher gas/oil ratio. During the third quarter of 2017, our production was made up of 39% natural gas and NGL volumes as compared to 31%decreases in the third quarter of 2016.
In addition to production-related increases in net revenue between periods, there were also significant increases in our average realized sales prices for oil, natural gas and NGLs, which decreased 32%, 80% and 54%, respectively, in the thirdsecond quarter of 20172023 compared to the same 20162022 period. Our average price for oil beforeThe 32% decrease in the effects of hedging increased 8%, our average price for natural gas before the effects of hedging increased 2% and our average price for NGLs increased 77% between periods. Of the 8% increase in our average realized oil price 7%was mainly the result of such increase was related to higher average32% lower NYMEX crude prices between periods, and the remaining 1% was attributable to slightly narrower oil differentials in the third quarter of 2017.periods. The 2% increase in our average realized sales price of natural gas price was similarly relateddecreased 80% mainly due to higher71% lower average NYMEX gas prices between periods (average NYMEXas well as a larger proportional gas prices being 5% higher between periods) which effect was partially offset by slightly wider gas differentials experienceddifferential in the thirdsecond quarter of 2017. Of2023 compared to the overall 77% increasesame 2022 period.The 54% decrease in average realized NGL prices between periods the majority of such increase was relatedprimarily attributable to higher averagelower Mont Belvieu spot prices for plant products fromin the thirdsecond quarter 2016of 2023 as compared to the thirdsecond quarter 2017,of 2022. The market prices for oil and natural gas have been impacted by global supply and demand constraints for oil and gas throughout 2022 and 2023 as discussed in the remaining increase in NGL price was attributable to the fact that in August of 2016 our gas processor began transporting our NGLs to sales points via pipeline rather than trucking them.market conditions section above.
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
Three Months Ended June 30,Increase/(Decrease)
20232022Change%
Operating costs (in thousands):
Lease operating expenses$82,991 $28,900 $54,091 187 %
Severance and ad valorem taxes48,927 34,695 14,232 41 %
Gathering, processing and transportation expenses21,753 25,756 (4,003)(16)%
Operating cost metrics:
Lease operating expenses (per Boe)$5.50 $4.52 $0.98 22 %
Severance and ad valorem taxes (% of revenue)7.8 %7.3 %0.5 %7 %
Gathering, processing and transportation expenses (per Boe)$1.44 $4.03 $(2.59)(64)%
 Successor  Predecessor
Increase/(Decrease)
 For the Three Months Ended September 30, 2017  For the Three Months Ended September 30, 2016
$
%
Operating expenses (in thousands):        
Lease operating expenses$11,373
  $3,656

$7,717

211 %
Severance and ad valorem taxes6,448
  1,432

5,016

350 %
Gathering, processing and transportation expenses9,925
  1,787

8,138

455 %
Production costs per Boe:        
Lease operating expenses$3.56
  $4.47

$(0.91)
(20)%
Severance and ad valorem taxes2.02
  1.75

0.27

15 %
Gathering, processing and transportation expenses3.11
  2.18

0.93
 43 %
Lease Operating Expenses.  Our lease Lease operating expenses (“LOE”) for the three months ended SeptemberJune 30, 2017 (Successor)2023 increased $7.7$54.1 million compared to the three months ended SeptemberJune 30, 2016 (Predecessor).2022. Higher LOE for the thirdsecond quarter of 20172023 was primarily related to a $6.0 million increase(i) additional costs associated with a higher well count. We added 49 gross wells through successful drilling and 57 gross wells from the Silverback and GMT Acquisitions. In addition, workover activity increased $1.7 million between periods as a result of our higher well count. We had 65309 gross operated horizontal wells acquired in the Merger on September 1, 2022; (ii) higher fixed and semi-variable well costs, such as of September 30, 2016 as compared to 171 gross operated horizontalwater disposal, monthly equipment rentals, repair work, wellhead chemical costs, labor, and electricity that all stemmed from the new wells as of September 30, 2017.drilled and the associated production increase between periods; and (iii) higher regulatory and preventative costs between periods.
Our LOE on a per Boe basis, on the other hand, decreased when comparing the third quarter of 2017 to the same 2016 period. LOE per Boe was $3.56$5.50 for the thirdsecond quarter of 2017,2023, which represents a decreasean increase of $0.91$0.98 per Boe (or 20%22%) from the thirdsecond quarter of 2016.2022. This decreaseincrease was primarily driven by (i) higher water disposal rates between periods, resulting from the sale of our operated saltwater disposal wells and associated produced water infrastructure in March 2023 (see Note 2—Acquisitions and Divestitures for additional information on this divestiture); and (ii) higher rental costs for oilfield equipment in the second quarter of 2023, which increased at a higher rate than increases in production. This increase was mainly due to flush production from new wells we drilled and completed over the past 12 months, which has the effect of reducing fixed and semi-variablepartially offset by lower per BOE workover costs on a per Boe basis.between periods.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the three months ended June 30, 2023 increased $14.2 million compared to the three months ended June 30, 2022. Severance taxes are primarily based on the market value of our oil and gas production at the wellhead, andwhile ad valorem taxes are generally based on the valuationassessed taxable value of ourproved developed oil and natural gas properties and vary across the different counties in which we operate. Severance and ad valorem taxes for the three months ended September 30, 2017 (Successor)

second quarter of 2023 increased $5.0$7.7 million (or 350%) compared to the three months ended September 30, 2016 (Predecessor), which wassame 2022 period primarily due to higher oil, natural gas and NGL revenues between periods. Ad valorem taxes between periods also increased $6.5 million due to higher tax assessment rates on our oil and gas reserve values, as well as the increase in our proved developed properties acquired in the Merger.
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Severance and ad valorem taxes as a percentage of our revenue was 5.8%total net revenues increased to 7.8% for the three months ended SeptemberJune 30, 20172023 as compared to 5.2%7.3% for the same 2016 period. Theprior year quarter. This increase in rate forwas the result of higher ad valorem taxes as discussed above, as well as net revenues being driven lower by a large portion of our GP&T costs being deducted from gas and NGL revenues during the three months ended SeptemberJune 30, 2017, however, is attributable to additional reserves and production in Texas resulting in higher ad valorem assessments,2023 as well as the New Mexico properties we added via the GMT Acquisition which carry a higher severance tax rate of 8.8%.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation expenses (“GP&T”) for the three months ended September 30, 2017 (Successor) increased $8.1 million compared to the three months ended SeptemberJune 30, 2016 (Predecessor) due2022. This decrease in net revenues resulted in severance and ad valorem taxes as a percentage of total net revenues to higherincrease period over period. Refer to Note 13—Revenues for additional information on our natural gas gathering and NGL volumes sold between periods, which in turn resulted in a higher amount of plant processing feescontracts.
Gathering, Processing and per unit transportation and gathering costs being incurred between periods.
OnTransportation Expenses. GP&T for the three months ended June 30, 2023 decreased $4.0 million as compared to the three months ended June 30, 2022. Additionally, GP&T decreased on a per Boe basis from $4.03 for the second quarter of 2022 to $1.44 for the second quarter of 2023. This decrease is due to the majority of our GP&T increased 43% from $2.18 for the third quarter of 2016costs being recognized as a reduction to $3.11 per Boe for the third quarter of 2017. This increase in rate was mainly due to a change in our gas/oil ratio whereby a higher percentage of our total production was made up of natural gas and NGL volumes duringrevenues in the thirdfirst quarter of 2017, and thus a higher proportion2023, while 100% of our production during this 2017 period was subjectGP&T costs were recognized as GP&T expense in the prior year period. This change in GP&T costs classification is required under ASC Topic 606, Revenue from contracts with Customers, due to the majority of gas gathering and transportation chargesprocessing contracts acquired in the Merger, as well as two of our existing gas processing fees. On a naturalcontracts that were amended and went into effect in November 2022, transferring control of our raw gas and NGL volumes basis (i.e. excluding crude oil barrels)at delivery points prior to, or at, the Boe rate increased only 14% between periodsinlet of gas processing plants. Refer to $7.93 from $6.95 for the third quarters of 2017 and 2016, respectively. This increase was primarily the result of a new firm transportation agreement we entered into in June 2017, which provides guaranteed pipeline capacity for the Company’s natural gas sales (refer to Note 13—Commitments and ContingenciesRevenues for additional information on such agreement).our natural gas gathering and processing contracts.
Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A&A”) for the periods indicated: 
Three Months Ended June 30,
(in thousands, except per Boe data)2023

2022
Depreciation, depletion and amortization$215,726 $82,117 
Depreciation, depletion and amortization per Boe$14.29 $12.85 
 Successor  Predecessor
(in thousands)For the Three Months Ended September 30, 2017  For the Three Months Ended September 30, 2016
Depreciation, depletion and amortization$42,387
  $18,454
Depreciation, depletion and amortization per Boe13.28
  22.56
For the three months ended June 30, 2023, DD&A expense amounted to $215.7 million, an increase of $133.6 million over the same 2022 period. The primary factor contributing to higher DD&A expense in 2023 was the increase in our overall production volumes between periods, which increased DD&A expense by $111.8 million, while our higher DD&A rate of $14.29 per BOE increased DD&A expense by $21.8 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 reserves ordeveloped and proved developedundeveloped reserves. For the three months ended September 30, 2017 (Successor),Our DD&A expense amounted to $42.4 million, an increase of $23.9 million over the same 2016 period (Predecessor). The primary factor contributing to higher DD&A in 2017 was the increase in overall production volumesrate increased $1.44 per Boe between periods which resulted in $53.5 million of incremental DD&A expense beingdue to (i) facility, infrastructure and artificial lift costs incurred during the thirdsecond quarter of 2017. This increase was largely offset, however, by a $29.6 million reduction in DD&A expense that was attributable2023, which have minimal associated proved reserve adds; and (ii) downward revisions to significantly lower DD&A rates between periods.
On a Boe basis our overall DD&A rate of $13.28 for the third quarter of 2017 was 41% lower than the rate of $22.56 for the same period in 2016. The primary factor contributing to this lower DD&A rate was substantial additions to our proved reserves and proved developed reserves, overprimarily natural gas reserves, during the past 12 months, coupled with reasonable drilling and completion costs over that same time period.
Exploration Expense. The following table summarizes our exploration expenses for the periods indicated: 
 Successor  Predecessor
(in thousands)For the Three Months Ended September 30, 2017  For the Three Months Ended September 30, 2016
Stock-based compensation expense$465
  $—
Geological and geophysical costs1,157
  402
Exploration expense$1,622
  $402
Exploration expense increased $1.2 million for the three months ended September 30, 2017 (Successor) compared to the same prior year period (Predecessor). Exploration expense mainly consists of topographical studies, geographical and geophysical (“G&G”) projects, and salaries and expenses of G&G personnel and consultants. The period over period increase in exploration expense is due to (i) seven geologist positions added since the thirdsecond quarter of 2016,2023 related to lower SEC reserve pricing and (ii) equity-based compensation awards that were granted to G&G personnel in 2017 and during the 2016 Successor period that were not likewise granted as of September 30, 2016.other factors.

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)20232022
Cash general and administrative expenses$17,694 $12,434 
Stock-based compensation - equity awards35,042 6,106 
Stock-based compensation - liability awards— (8,593)
General and administrative expenses$52,736 $9,947 
 Successor  Predecessor
(in thousands)For the Three Months Ended September 30, 2017  For the Three Months Ended September 30, 2016
Stock-based compensation expense$3,360
  $—
Cash general and administrative expenses9,951
  4,848
General and administrative expenses$13,311
  $4,848
G&A expenses for the three months ended SeptemberJune 30, 2017 (Successor) increased $8.52023 were $52.7 million overcompared to $9.9 million for the same 2016 period (Predecessor).three months ended June 30, 2022. Higher G&A in the second quarter of 2023 was mainly the result of a $37.5 million increase in total stock-based compensation between periods. This increase was primarily due to $5.9(i) an increase of $28.9 million in higherequity awards compensation period over period for the acceleration of certain awards in the second quarter of 2023 as a result of officer and employee salariesexits stemming from the Merger; and (ii) an increase of $8.6 million period over period related costs between periods and $3.4 million of stock-based compensation incurredto liability awards, as we no longer had any liability-based equity awards outstanding during the thirdsecond quarter of 2017 versus none2023. Refer to Note 6—Stock-Based Compensation for additional information regarding these awards. In addition, cash G&A increased $5.3 million between periods. This increase was mainly related to (i) higher payroll and employee-related costs associated with our G&A headcount, which increased from 114 as of June 30, 2022 to 175 as of June 30, 2023 stemming from the 2022 Merger; (ii) higher professional and legal fees between periods; and (iii) higher rent expense in the same prior year period. Employee-related costs were substantially higher during the thirdsecond quarter of 2017 due2023 associated with a greater quantity of office space following the Merger.
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Merger and integration expense. Merger and integration expense for the three months ended June 30, 2023 was $4.4 million compared to $5.7 million for the number of administrative employees (i.e. non-billablethree months ended June 30, 2022. This decrease period over period relates to our joint interest partners) increasing from 29 at September 30, 2016 to 94 at September 30, 2017. These increases werea $3.9 million decrease in consultancy, legal and advisory fees, partially offset by a decrease$2.6 million increase in transactionseverance and related benefits associated with employee terminations in connection with the Merger.
Impairment and Abandonment Expense. During the three months ended June 30, 2023, impairment and abandonment expense was $0.2 million as compared to $0.5 million during the three months ended June 30, 2022. Both periods consist solely of amortization of leasehold expiration costs between periods. Thereassociated 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)2023

2022
Geological and geophysical costs$3,751 $1,534 
Stock-based compensation - equity awards652 551 
Other expenses860 (131)
Exploration and other expenses$5,263 $1,954 
Exploration and other expenses were $1.1$5.3 million for the three months ended June 30, 2023 compared to $2.0 million for the three months ended June 30, 2022. Exploration and other expenses mainly consist of Silver Run acquisitiontopographical 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 related to (i) increased costs incurred duringon G&G projects and seismic studies of $1.6 million; (ii) $0.9 million in costs incurred in 2023 associated with a nonrecurring legal settlement; and (iii) higher G&G personnel costs in the thirdsecond quarter of 2016, while no such costs were similarly incurred during the third quarter of 2017.2023 associated with increased headcount.
Other Income and Expenses.
Interest Expense. The following table summarizes our interest expensesexpense for the periods indicated:
Three Months Ended June 30,
(in thousands)20232022
Credit facility$7,667 $772 
5.375% Senior Notes due 20263,889 3,889 
7.75% Senior Notes due 20265,813 — 
6.875% Senior Notes due 20276,125 6,125 
3.25% Convertible Senior Notes due 20281,381 1,381 
5.875% Senior Notes due 202910,281 — 
Amortization of debt issuance costs and debt discount3,482 2,734 
Interest capitalized(2,117)(575)
Financing lease interest obligation305 — 
Total$36,826 $14,326 
 Successor  Predecessor
(in thousands)For the Three Months Ended September 30, 2017  For the Three Months Ended September 30, 2016
Credit facility$1,480
  $990
Term Loan—
  993
Interest capitalized(465)  —
Total$1,015
  $1,983
ForInterest expense increased $22.5 million for the three months ended SeptemberJune 30, 2017 (Successor), we incurred $1.5 million in interest related2023 as compared to CRP’s credit facility of which $0.5 million was capitalized as it was utilized to fund the Company’s drilling and completion capital expenditures. For the three months ended SeptemberJune 30, 2016 (Predecessor), we recorded $1.02022 primarily due to (i) $16.1 million in additional interest related to CRP’s credit facilitycosts on the senior notes we assumed in the Merger; and $1.0(ii) $6.9 million in higher interest relatedincurred on our Credit Agreement due to CRP’s term loan, which was extinguished uponadditional borrowings outstanding and higher interest rates during the closing of the Business Combination. 2023 period.
Our weighted average debtborrowings outstanding during the third quarter of 2017 was $108.5under our Credit Agreement were $370.2 million versus $124.0and $5.4 million for the third quarter of 2016.three months ended June 30, 2023 and 2022, respectively. Our Credit Agreement’s weighted average effective interest rate was 3.77% during the third quarter of 2017 comparedincreased to 2.79%7.1% from 2.7% for the third quarter of 2016.three months ended June 30, 2023 and 2022, respectively, due to higher rates on our variable-rate borrowings between periods.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of i) fluctuations(i) changes in mark-to-market derivative fair values associated with corresponding changesfluctuations in the forward price curves for the commodities underlying commodity priceseach of our hedge contracts outstanding; and ii)(ii) monthly cash settlements on any closed out hedge positions during the period.
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The following table presents gains and losses on our hedged derivative positions. Forinstruments for the three month periods ended September 30, 2017 (Successor) and 2016 (Predecessor), we recognized non-cash mark-to-market derivative losses of $1.3 million and $0.2 million, respectively. Cash derivative settlements, on the other hand, amounted to $0.4 million and $2.0 million in gains for both the third quarters of 2017 and 2016, respectively.indicated:
Three Months Ended June 30,
(in thousands)20232022
Realized cash settlement gains (losses)$39,279 $(73,648)
Non-cash mark-to-market derivative gain (loss)(18,678)39,514 
Total$20,601 $(34,134)
Income Tax Expense(Expense) Benefit. During the three months ended September 30, 2017 (Successor) the Company recognized $8.2 million inThe following table summarizes our pre-tax income (loss) and income tax expense. The Company's provision(expense) benefit for the periods indicated:
Three Months Ended June 30,
(in thousands)20232022
Income (loss) before income taxes$175,502 $233,313 
Income tax (expense) benefit(26,548)(41,487)
Our provisions for income taxes for the three months ended SeptemberJune 30, 2017 differed2023 and 2022 differs from the amountamounts that would be provided by applying the statutory U.S. federal taxstatutory rate of 35%21% to pre-tax book income (loss) primarily becausedue to (i) the portion of pre-tax net income that is attributable to our non-controlling interest and which is therefore not taxable to the Company; (ii) other permanent differences; (iii) state income taxestaxes; and permanent differences.(iv) changes during the period in our deferred tax asset valuation allowance, if any.

For the three months ended June 30, 2023, we generated pre-tax net income of $175.5 million and recorded income tax expense of $26.5 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the portion of pre-tax income that was attributable to our non-controlling interest partners and not taxable to the Company.
NineFor 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 in the second quarter of 2022.
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Six Months Ended SeptemberJune 30, 2017 (Successor)2023 Compared to NineSix Months Ended SeptemberJune 30, 2016(Predecessor)2022
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:
 Successor  Predecessor Increase/(Decrease)
 For the Nine Months Ended September 30, 2017  For the Nine Months Ended September 30, 2016 $ %
Net revenues (in thousands):        
Oil sales$204,702
  $56,975
 $147,727
 259 %
Natural gas sales33,226
  5,717
 27,509
 481 %
NGL sales25,844
  3,097
 22,747
 734 %
Total net revenues$263,772
  $65,789
 $197,983
 301 %
         
Average sales prices:        
Oil (per Bbl)$45.76
  $37.48
 $8.28
 22 %
Effect of derivative settlements on average price (per Bbl)0.12
  15.30
 (15.18) (99)%
Oil net of hedging (per Bbl)$45.88
  $52.78
 $(6.90) (13)%
         
Average NYMEX price for oil (per Bbl)$49.44
  41.43
 8.01
 19 %
         
Natural gas (per Mcf)$2.78
  $2.24
 $0.54
 24 %
Effect of derivative settlements on average price (per Mcf)(0.02)  —
 (0.02) 100 %
Natural gas net of hedging (per Mcf)$2.76
  $2.24
 $0.52
 23 %
         
Average NYMEX price for natural gas (per Mcf)$3.05
  2.34
 0.71
 30 %
         
NGL (per Bbl)$23.67
  $12.80
 $10.87
 85 %
         
Net production:        
Oil (MBbls)4,473
  1,520
 2,953
 194 %
Natural gas (MMcf)11,938
  2,551
 9,387
 368 %
NGL (MBbls)1,092
  242
 850
 351 %
Total (MBoe) (1)
7,554
  2,187
 5,367
 245 %
         
Average daily net production volume:        
Oil (Bbls/d)16,384
  5,547
 10,837
 195 %
Natural gas (Mcf/d)43,729
  9,310
 34,419
 370 %
NGL (Bbls/d)3,999
  883
 3,116
 353 %
Total (Boe/d) (1)
27,670
  7,982
 19,688
 247 %
Six Months Ended June 30,Increase/(Decrease)
20232022$%
Net revenues (in thousands):
Oil sales$1,073,612 $612,358 $461,254 75 %
Natural gas sales(1)
55,769 107,048 (51,279)(48)%
NGL sales(2)
110,285 100,525 9,760 10 %
Oil and gas sales$1,239,666 $819,931 $419,735 51 %
Average sales prices:
Oil (per Bbl)$72.89 $97.42 $(24.53)(25)%
Effect of derivative settlements on average price (per Bbl)3.53 (15.03)18.56 123 %
Oil including the effect of hedging (per Bbl)$76.42 $82.39 $(5.97)(7)%
Average NYMEX WTI price for oil (per Bbl)$74.95 $101.37 $(26.42)(26)%
Oil differential from NYMEX(2.06)(3.95)1.89 48 %
Natural gas price excluding the effects of GP&T (per Mcf)(1)
$1.52 $5.13 $(3.61)(70)%
Effect of derivative settlements on average price (per Mcf)0.55 (1.06)1.61 152 %
Natural gas including the effects of hedging (per Mcf)$2.07 $4.07 $(2.00)(49)%
Average NYMEX Henry Hub price for natural gas (per MMBtu)$2.39 $6.00 $(3.61)(60)%
Natural gas differential from NYMEX(0.87)(0.87)— — %
NGL price excluding the effects of GP&T (per Bbl)(2)
$23.69 $46.74 $(23.05)(49)%
Net production:
Oil (MBbls)14,730 6,286 8,444 134 %
Natural gas (MMcf)49,066 20,866 28,200 135 %
NGL (MBbls)6,029 2,151 3,878 180 %
Total (MBoe)(3)
28,937 11,914 17,023 143 %
Average daily net production:
Oil (Bbls/d)81,379 34,729 46,650 134 %
Natural gas (Mcf/d)271,080 115,280 155,800 135 %
NGLs (Bbls/d)33,310 11,881 21,429 180 %
Total (Boe/d)(3)
159,869 65,824 94,045 143 %
(1)
Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

(1)    Natural gas sales for the six months ended June 30, 2023 include $18.7 million of GP&T that are reflected as a reduction to natural gas sales and zero for the six months ended June 30, 2022. Natural gas average sales price, however, excludes $0.38 per Mcf of these GP&T charges for the six months ended June 30, 2023.
(2)    NGL sales for the six months ended June 30, 2023 include $32.6 million of GP&T that are reflected as a reduction to NGL sales and zero for the six months ended June 30, 2022. NGL average sales price, however, excludes $5.40 per Bbl of these GP&T charges for the six months ended June 30, 2023.
(3)    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. Our totalTotal net revenues for the ninesix months of 2017 (Successor)ended June 30, 2023 were $198.0$419.7 million, (or 301%)or 51%, higher than total net revenues for the ninesix months of 2016 (Predecessor). Our revenuesended June 30, 2022. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Our netNet production volumes for oil, natural gas, and NGLs increased 194%134%, 368%135%, and 351%180%, respectively, between periods. The oil production volume increase between periods resulted primarily from our drilling successplacing 140 wells online production since the second quarter of 2022 as compared to 50 wells brought online since the second quarter of 2021. Oil production in the Delaware Basin, as well as the producing properties wecurrent period also benefited from wells acquired in the Silverback and GMT Acquisitions,Merger with Colgate, which collectively added 603 MBbls of net oil production to our nine months ended September 30, 2017 results. Since the third quarter of 2016, we have placed 49 operated wells on production in the Delaware Basin, which has added 2,8263,475 MBbls of net oil production to the first ninesix months of 2017. The increase in our operated well count is attributable to the ramp up of our drilling program starting in the fourth quarter of 2016.ended June 30, 2023. These oil volume increases were partially offset by normal production declines across our existing wells. Our naturalNatural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in our oil quantities sold and our natural gas and NGL quantities sold. Naturalsold driving the 135% and 180%, respective, increase in gas and NGL volumes between periods.
These increases were also impactedpartially offset by the acreage we acquired from Silverback, which has a higher gas/oil ratio. During the nine months ended September 30, 2017, our production was made up of 41% natural gas and NGL volumes as compared to 31%decreases in the same 2016 period.
In addition to production-related increases in net revenue between periods, there were also significant increases in our average realized sales prices for oil, natural gas and NGLs, when comparingwhich decreased 25%, 70%, and 49%, respectively, in the nine months ended September 30, 2017first half of 2023 compared to the same 20162022 period. Our average price for oil beforeThe 25% decrease in the effects of hedging increased 22%, our average price for natural gas before the effects of hedging increased 24%, and our average price for NGLs increased 85% between periods. Of the 22% increase in our average realized oil price 19%was mainly the result of such increase was related to higher average26% lower NYMEX crude prices between periods, and the remaining 3% was attributableslightly offset by improved oil differentials. The average realized sales price of natural gas decreased 70% due to slightly narrower oil differentials60% lower average NYMEX gas prices between periods as well as a larger proportional gas differential in the first nine monthshalf of 2017.2023 compared to the same 2022 period. The 24% increase in our average realized natural gas price was similarly related to higher NYMEX prices between periods (NYMEX natural gas prices being up 30% between periods) which effect was partially offset by wider gas differentials experienced in the nine months ended September 30, 2017. Of the overall 85% increase49% decrease in average realized NGL prices between periods the majority of such increase was relatedprimarily attributable to higher averagelower Mont Belvieu spot prices for plant products fromfor the nine months ended September 30, 2016first half of 2023 as compared to the comparable 2017 period. Additionally, NGLfirst half of 2022. The market prices increased beginningfor oil and natural gas have been impacted by global supply and demand constraints for oil and gas throughout 2022 and 2023 as discussed in August 2016 as a result of lower transportation costs incurred by our gas processor due to the use of pipeline versus prior trucking alternatives.market conditions section above.
Operating Expenses. The following table sets forth selectedsummarizes our operating expense dataexpenses for the periods indicated:
Six Months Ended June 30,Increase/(Decrease)
2023

2022Change%
Operating costs (in thousands):
Lease operating expenses$157,523 $57,634 $99,889 173 %
Severance and ad valorem taxes97,436 59,746 37,690 63 %
Gathering, processing and transportation expenses37,235 47,647 (10,412)(22)%
Operating cost metrics:
Lease operating expenses (per Boe)$5.44 $4.84 $0.60 12 %
Severance and ad valorem taxes (% of revenue)7.9 %7.3 %0.6 %8 %
Gathering, processing and transportation expenses (per Boe)$1.29 $4.00 $(2.71)(68)%
 Successor  Predecessor Increase/(Decrease)
 For the Nine Months Ended September 30, 2017  For the Nine Months Ended September 30, 2016 $ %
Operating Expenses (in thousands):        
Lease operating expenses$26,924
  $10,295
 $16,629
 162 %
Severance and ad valorem taxes14,358
  3,523
 10,835
 308 %
Gathering, processing and transportation expenses22,572
  4,375
 18,197
 416 %
Production costs per Boe:        
Lease operating expenses$3.56
  $4.71
 $(1.15) (24)%
Severance and ad valorem taxes1.90
  1.61
 0.29
 18 %
Gathering, processing and transportation expenses2.99
  2.00
 0.99
 50 %
Lease Operating Expenses. Our LOE for the ninesix months ended SeptemberJune 30, 2017 (Successor)2023 increased $16.6$99.9 million compared to the comparable 2016 period (Predecessor).six months ended June 30, 2022. Higher LOE for the first nine monthshalf of 20172023 was primarily related to a $12.6 million increase(i) additional costs associated with a higher well count. We added 49 gross wells through successful drilling and 57 gross wells from the Silverback and GMT Acquisitions. In addition, workover activity increased $4.0 million between periods as a result of our higher well count. We had 65309 gross operated horizontal wells acquired in the Merger on September 1, 2022; (ii) higher fixed and semi-variable well costs, such as of September 30, 2016 as compared to 171 gross operated horizontalwater disposal, monthly equipment rentals, repair work, wellhead chemical costs, labor, and electricity that all stemmed from new wells as of September 30, 2017.drilled and the associated production increase between periods; and (iii) higher regulatory and preventative costs between periods.
Our LOE on a per Boe basis, on the other hand, decreased when comparing the nine months ended September 30, 2017 to the same 2016 period. LOE per Boe was $3.56$5.44 for the ninesix months ended SeptemberJune 30, 2017,2023, which represents a decreasean increase of $1.15$0.60 per Boe (or 24%12%) from the ninesix months ended SeptemberJune 30, 2016.2022. This decrease in rateincrease was mainly due to flush production from new wells we drilled and completed over the past 12 months, which has the effect of reducing fixed and semi-variable costs on aprimarily driven by per Boe basis.increases associated with (i) higher water disposal rates between periods, resulting from the sale of our operated saltwater disposal wells and associated produced water infrastructure in March 2023 (see Note 2—Acquisitions and Divestitures for additional information on the divestiture); and (ii) higher rental costs for oilfield equipment during the first half of 2023, which increased at a higher rate than increases in production. This increase was partially offset by lower per BOE workover expenses between periods.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the six months ended June 30, 2023 increased $37.7 million compared to the six months ended June 30, 2022. Severance taxes are primarily based on the market value of our production at the wellhead, andwhile ad valorem taxes are generally based on the valuationassessed taxable value of our proved developed oil and natural gas properties and vary across the different

counties in which we operate. Severance and ad valorem taxes for the nine months ended September 30, 2017 (Successor)first half of 2023 increased $10.8$25.7 million (or 308%) compared to the nine months ended September 30, 2016 (Predecessor) which wassame 2022 period primarily due to higher oil, natural gas and NGL revenues between periods. Ad valorem taxes between periods also increased $12.0 million due to higher tax assessments on our oil and gas reserve values as well as an increase in our oil and gas properties as a result of the Merger.
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Severance and ad valorem taxes as a percentage of our revenue remained consistenttotal net revenues increased to 7.9% for the nine months ended September 30, 2017 and 2016 at 5.4%.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”)first half of 2023 as compared to 7.3% for the nine months ended September 30, 2017 (Successor) increased $18.2 million compared to the same 2016 period (Predecessor) due to higher natural gas and NGL volumes sold between periods, which in turn resulted in a higher amount of plant processing fees and per unit transportation and gathering costs being incurred between periods.
On a per Boe basis, our GP&T increased 50% from $2.00 for the nine months ended September 30, 2016 to $2.99 per Boe for the comparable 20172022 period. This increase in rate was mainly attributable to the change in our gas/oil ratio wherebyresult of higher ad valorem taxes as discussed above, as well as net revenues being driven lower by a higher percentagelarge portion of our total production was made up of naturalGP&T costs being deducted from gas and NGL volumesrevenues during the nine months ended September 30, 2017,first half of 2023 compared to the first half of 2022. This decrease in net revenues resulted in severance and thusad valorem taxes as a higher proportionpercentage of our production during this 2017total net revenues to increase period was subjectover period. Refer to gas gathering and transportation charges as well as gas processing fees. On a natural gas and NGL volumes basis (i.e. excluding crude oil barrels) the Boe rate increased only 12% between periods from $6.56 to $7.32 for the nine months ended September 30, 2016 and 2017, respectively. This increase was primarily the result of a new firm transportation agreement we entered into in June 2017, which provides guaranteed pipeline capacity for the Company’s natural gas sales (refer to Note 13—Commitments and ContingenciesRevenues for additional information on such agreement).our natural gas gathering and processing contracts.
Gathering, Processing and Transportation Expenses. GP&T for the six months ended June 30, 2023 decreased $10.4 million compared to the six months ended June 30, 2022. Additionally, GP&T decreased on a per Boe basis from $4.00 for the first half of 2022 to $1.29 for the same 2023 period. This decrease is due to the majority of our GP&T costs being recognized as a reduction to our gas and NGL revenues in the first half of 2023, while 100% of our GP&T costs were recognized as GP&T expense in the prior year period. This change in GP&T costs classification is required under ASC Topic 606, Revenue from contracts with Customers, due to the majority of gas processing contracts acquired in the Merger, as well as one of our existing processing contracts that were amended and went into effect in November 2022, transferring control of our raw gas at delivery points prior to, or at, the inlet of gas processing plants. Refer to Note 13—Revenues for additional information on our natural gas gathering and processing contracts.
Depreciation, Depletion and Amortization. The following table summarizes our DD&A for the periods indicated:
Six Months Ended June 30,
(in thousands, except per Boe data)20232022
Depreciation, depletion and amortization$403,945 $153,126 
Depreciation, depletion and amortization per Boe$13.96 $12.85 
 Successor  Predecessor
(in thousands)For the Nine Months Ended September 30, 2017  For the Nine Months Ended September 30, 2016
Depreciation, depletion and amortization$102,847
  $60,939
Depreciation, depletion and amortization per Boe13.61
  27.86
For the six months ended June 30, 2023, DD&A expense amounted to $403.9 million, an increase of $250.8 million over the same 2022 period. The primary factor contributing to higher DD&A expense in 2023 was the increase in our overall production volumes between periods, which increased DD&A expense by $218.8 million during the first half of 2023, while higher DD&A rates between periods increased DD&A expense by $32.0 million for the six months ended June 30, 2023.
Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved reserves ordeveloped and proved developedundeveloped reserves. For the nine months ended September 30, 2017 (Successor),Our DD&A expense amounted to $102.8 million, an increase of $41.9 million over the same 2016 period (Predecessor). The primary factor contributing to higher DD&A in 2017 was the increase in overall production volumesrate increased $1.11 per Boe between periods which resulted in $149.5 million of incremental DD&A expense beingdue to (i) facility, infrastructure and artificial lift costs incurred during the first nine monthshalf of 2017. This increase was largely offset, however, by a $107.6 million reduction in DD&A expense that was attributable2023, which have minimal associated proved reserve adds; and (ii) downward revisions to significantly lower DD&A rates between periods.
On a Boe basis our overall DD&A rate of $13.61 for the nine months ended September 30, 2017 was 51% lower than the rate of $27.86 for the same period in 2016. The primary factor contributing to this lower DD&A rate was substantial additions to our proved reserves and proved developed reserves, over the past 12 months, coupled with reasonable drilling and completion costs over that same time period.
Exploration Expense. The following table summarizes our exploration expenses for the periods indicated: 
 Successor  Predecessor
(in thousands)For the Nine Months Ended September 30, 2017  For the Nine Months Ended September 30, 2016
Stock-based compensation expense$1,132
  $—
Geological and geophysical costs2,960
  920
Exploration expense$4,092
  $920
Exploration increased $3.2 million for the nine months ended September 30, 2017 (Successor) compared to the same 2016 period (Predecessor). Exploration expense mainly consists of costs of topographical studies, G&G projects, and salaries and expenses of G&G personnel and consultants. The period over period increase in exploration expense is due to (i) seven geologist positions added since the third quarter of 2016, and (ii) equity-based compensation awards that were granted to G&G personnel in 2017 andprimarily natural gas reserves, during the 2016 Successor period that were not likewise granted asfirst half of September 30, 2016.2023 related to lower SEC reserve pricing and other factors.

General and Administrative Expenses. The following table summarizes our G&A expenses for the periods indicated:
Six Months Ended June 30,
(in thousands)2023

2022
Cash general and administrative expenses$36,461 $24,203 
Stock-based compensation expense - equity awards51,749 11,220 
Stock-based compensation expense - liability awards— 5,127 
General and administrative expenses$88,210 $40,550 
 Successor  Predecessor
(in thousands)For the Nine Months Ended September 30, 2017  For the Nine Months Ended September 30, 2016
Stock-based compensation expense$8,288
  $—
Cash general and administrative expenses27,729
  9,735
General and administrative expenses$36,017
  $9,735
G&A expenses for the ninesix months ended SeptemberJune 30, 2017 (Successor) increased $26.32023 were $88.2 million overcompared to $40.6 million for the same 2016 period (Predecessor).six months ended June 30, 2022. Higher G&A for the first six months of 2023 was the result of a $35.4 million increase in total stock-based compensation expense between periods. This increase was primarilylargely due to $14.7an increase in equity awards compensation period over period for the acceleration of certain awards during the first six months of 2023 as a result of officer and employee exits stemming from the Merger, which was slightly offset by a decrease in stock-based compensation for liability awards period over period, as we no longer had any liability-based equity awards outstanding during the first half of 2023. Refer to Note 6—Stock-Based Compensation for additional information regarding these awards. Additionally, cash G&A increased $12.3 million between periods. This increase was mainly related to (i) higher payroll and employee-related costs associated with our increased G&A headcount, which went from 114 as of June 30, 2022 to 175 as of June 30, 2023 stemming from the 2022 Merger; (ii) higher professional and legal fees between periods; and (iii) higher rent expense between periods due to increased office space following the Merger.
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Merger and integration expense. Merger and integration expense for the six months ended June 30, 2023 was $17.6 million compared to $5.7 million during the six months ended June 30, 2022. This increase period over period relates to $13.7 million in higher employee salariesseverance and related costs between periods, $8.3benefits associated with employee terminations in connection with the Merger, which was partially offset by a $1.8 million of stock-based compensation incurreddecrease in consultancy, legal and advisory fees.
Impairment and Abandonment Expense. During the six months ended June 30, 2023, impairment and abandonment expense was $0.5 million as compared to $3.1 million during the ninesix months ended SeptemberJune 30, 2017 versus none in2022. 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:
Six Months Ended June 30,
(in thousands)2023

2022
Geological and geophysical costs$6,072 $3,237 
Stock-based compensation - equity awards1,816 982 
Other expenses1,749 42 
Exploration and other expenses$9,637 $4,261 
Exploration and other expenses were $9.6 million for the six months ended June 30, 2023 compared to $4.3 million for the same prior year period. Exploration and other expenses mainly consist of topographical studies, G&G projects, salaries and expenses of G&G personnel and includes other operating costs. The period over period increase was primarily related to (i) increased costs incurred on G&G projects and $2.9seismic studies of $1.5 million; (ii) $1.4 million in increased professional fees. Employee-relatedhigher G&G personnel costs were substantially higher duringin the nine months ended September 30, 2017 due to the numberfirst half of administrative employees (i.e. non-billable to our joint interest partners) increasing from 29 at September 30, 2016 to 94 as of September 30, 2017, and professional fees were also higher due to costs2023 associated with beingincreased headcount; (iii) $0.9 million in costs incurred in 2023 associated with a public company that were incurred duringnonrecurring legal settlement; and (iv) $0.8 million in higher stock-based compensation related to accelerated vesting of employees terminated in connection with the 2017 period.Merger.
Other Income and Expenses.
Gain on Sale of Oil and Natural Gas Properties. Duringthe nine months ended September 30, 2017 (Successor), we recorded a gain on sale of oil and natural gas properties of $7.2 million primarily related to the sale of our Pecos County, Texas acreage.
Interest Expense. The following table summarizes our interest expensesexpense for the periods indicated:
Six Months Ended June 30,
(in thousands)20232022
Credit facility$16,159 $1,649 
5.375% Senior Notes due 20267,778 7,778 
7.75% Senior Notes due 202611,626 — 
6.875% Senior Notes due 202712,250 12,250 
3.25% Convertible Senior Notes due 20282,762 2,762 
5.875% Senior Notes due 202920,562 — 
Amortization of debt issuance costs and debt discount6,278 4,226 
Interest capitalized(4,117)(1,185)
Financing lease interest obligation305 — 
Total$73,603 $27,480 
 Successor  Predecessor
(in thousands)For the Nine Months Ended September 30, 2017  For the Nine Months Ended September 30, 2016
Credit facility$2,633
  $2,403
Term Loan—
  3,019
Interest capitalized(501)  —
Total$2,132
  $5,422
ForInterest expense was $46.1 million higher for the ninesix months ended SeptemberJune 30, 2017 (Successor), we incurred $2.62023 compared to the same 2022 period mainly due to (i) $32.2 million in additional interest related to CRP’s credit facility of which $0.5 million was capitalized as it was utilized to fund the Company’s drilling and completion capital expenditures. For the nine months ended September 30, 2016 (Predecessor), we recorded $2.4 million in interest related to CRP’s credit facility and $3.0 millioncosts on the term loan, which was extinguished upon closing ofsenior notes we assumed in the Business Combination. Merger; and (ii) $14.5 million higher interest incurred on our Credit Agreement due to higher borrowings outstanding and higher interest rates during the 2023 period.
Our weighted average debtborrowings outstanding for the nine months ended September 30, 2017 was $46.1under our Credit Agreement were $412.7 million versus $99.5$16.5 million for the same 2016 period.first half of 2023 and 2022, respectively. Our Credit Agreement’s weighted average effective interest rate was 3.72% during6.9% and 2.9% for the ninesix months ended SeptemberJune 30, 2017 compared to 2.67% for the comparable 2016 period.2023 and 2022, respectively.
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Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of i) fluctuations(i) changes in mark-to-market derivative fair values associated with corresponding changesfluctuations in the forward price curves for the commodities underlying commodity prices.each of our hedge contracts outstanding and ii)(ii) monthly cash settlements ofon any closed out hedge positions during the period.
The following table presents gains and losses on our hedged derivative positions. For the nine months ended September 30, 2017 (Successor), we recognized non-cash mark-to-market derivative gains of $5.1 million compared to non-cash mark-to-market losses of $20.8 millioninstruments for the same 2016 period (Predecessor)periods indicated:
Six Months Ended June 30,
(in thousands)20232022
Realized cash settlement gains (losses)$79,014 $(116,526)
Non-cash mark-to-market derivative gain (loss)(3,901)(47,131)
Total$75,113 $(163,657)
Income Tax (Expense) Benefit. Cash derivative settlements amounted to $0.3 millionThe following table summarizes our pre-tax income (loss) and $16.6 million in gainsincome tax (expense) benefit for the nine months of 2017 and 2016, respectively.periods indicated:
Income Tax Expense. During the nine months ended September 30, 2017 (Successor) the Company recognized $17.3 million income tax expense. The Company's provision
Six Months Ended June 30,
(in thousands)20232022
Income (loss) before income taxes$429,557 $255,891 
Income tax (expense) benefit(60,802)(48,263)
Our provisions for income taxes for the nine months ended September 30, 2017 differedfirst half of 2023 and 2022 differs from the amountamounts that would be provided by applying the blended statutory U.S. federal state, and local income taxstatutory rate of 36.1%21% to pre-tax book income (loss) primarily becausedue to (i) the Company released $5.1 millionportion of itspre-tax net income that is attributable to our non-controlling interest and which is therefore not taxable to the Company; (ii) other permanent differences; (iii) state income taxes; and (iv) any changes during the period in our deferred tax asset valuation allowance.
For the six months ended June 30, 2023 we generated pre-tax net income of $429.6 million and recorded income tax expense of $60.8 million. The primary factors decreasing our income tax expense below the U.S. statutory rate was the portion of pre-tax income that was attributable to our non-controlling interest partners and not taxable to the Company.
For the six months ended June 30, 2022, we generated pre-tax net income of $255.9 million and recorded income tax expense of $48.3 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the partial release of our deferred tax valuation allowance induring the first half of 2017, such that income tax expense2022.

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Table of $17.3 million for the nine months ended September 30, 2017 was partially offset by the tax benefit associated with the portion of the valuation allowance released resulting in an effective tax rate of 25.6%.Contents


Liquidity and Capital Resources
Overview
Our developmentdrilling and acquisitioncompletion activities require us to make significant operating and capital expenditures. Historically, our primary sources of liquidity have been borrowings under CRP’s revolving credit facility, cash flows from operations, andborrowings under our revolving credit facility, proceeds from offerings of debt or equity securities, or proceeds from the sale of oil and priorgas properties. Our future cash flows are subject to the Business Combination, capital contributions from CRP’s Sponsors.a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary use of capital has been for drilling and development capital expenditures and the acquisition of oil and natural gas properties.
The following table summarizes our capital expenditures incurred for the nine months ended September 30, 2017:
(in millions)Nine Months Ended September 30, 2017
Drilling and completion capital expenditures$398.4
Land and other40.5
Facilities, seismic and other11.3
Total capital expenditures450.2
We continually evaluate our capital needs and compare them to our capital resources. We operated a seven-rig drilling program during the first six months of 2023. Our estimatedtotal capital expenditureexpenditures incurred for the six months ended June 30, 2023 were $745.5 million. We expect our total drilling, completion and facilities capital expenditures budget for 2017 is $535.0 million2023 to $625.0 million, which we expectbe between $1.25 billion to fund with$1.45 billion. We funded our capital expenditures for the six months ended June 30, 2023 entirely from cash flows from operations, and borrowings.we expect to fund our 2023 capital expenditures budget entirely from cash flows from operations given our anticipated level of oil and gas production, current commodity prices and our commodity hedge positions in place.
We plan to return capital to shareholders through a combination of base dividends plus a variable return program, including variable dividends, share repurchases or a combination of both. During the six months ended June 30, 2023, we declared a quarterly cash dividend of $0.05 per share of Class A Common Stock and a quarterly cash distribution of $0.05 per Common Unit of OpCo for each of the first two quarters of 2023. Additionally, during the second quarter of 2023, our Board of Directors declared an initial variable cash dividend of $0.05 per share of Class A Common Stock and a variable cash distribution of $0.05 per Common Unit of OpCo. The drillingcash dividends and completion (“D&C”) portiondistributions paid totaled $85.5 million for the six months ended June 30, 2023. Additionally, as a part of our 2017 capital budget represents a significant increase over the $97.7shareholder return program, we repurchased 2.8 million shares of D&C expenditures incurred during 2016. This increased capital budget is in response to the higher level of anticipated future prices and cash flows to be generated from (i) new wells we drilled and completed in latter 2016 and plan to drill and complete in 2017, (ii) wells and locations we added from the Silverback Acquisition and GMT Acquisition and (iii) higher crude oil and natural gas prices experiencedClass C Common Stock for $29.4 million under our stock repurchase program during the fourth quartersix months ended June 30, 2023.
    The stock repurchase program can be used to reduce our shares of 2016Common Stock outstanding. Such repurchases would be made at terms and continuing into 2017, as well asprices determined by us based upon prevailing market conditions, applicable legal requirements, available liquidity, compliance with our strong balance sheet position.debt and other agreements and other factors. In addition, we may, from time to time, seek to retire or purchase our outstanding senior notes through cash purchases and/or exchanges for debt in open-market purchases, privately negotiated transactions or otherwise.
Because we are the operator of a high percentage of our acreage, we can control the amount and timing of theseour capital expenditures are largely discretionary.expenditures. We couldcan choose to defer or accelerate a portion of theseour planned capital expenditures depending on a variety of factors, including but not limited to, the success of our drilling activities,to: prevailing and anticipated prices for oil and natural gas,gas; oil storage or transportation constraints; the success of our drilling activities; the availability of necessary equipment, infrastructure and capital,capital; the receipt and timing of required regulatory permits and approvals,approvals; seasonal conditions, drilling andconditions; property or land acquisition costscosts; and the level of participation by other working interest owners.
Based upon current oil and natural gas price expectations for the remainder of 2017, we believe that our cash flow from operations and borrowings will provide us with sufficient liquidity to execute our current capital program. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot ensure that cash flows from operations andor other sources of needed capital will be available onat acceptable terms or at all. InFurther, our ability to access the event we make additional acquisitionspublic or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the amountvalue and performance of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional sources for funding capital investments. As we pursue our future development program, we are actively assessing the correct mix of reserve base borrowings and debt offerings. If we require additional capital to fund acquisitions, we may also seek such capital through traditional reserve base borrowings, offerings of debt andor equity securities, asset sales or other means. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.
Working Capital Analysis
Our cash balances were $2.6 million and $134.1 million as of September 30, 2017 and December 31, 2016, respectively. Due to the amounts that we incur related to our drilling program, we may have temporary working capital deficits. However, we expect that our cash flows from operating activities and future borrowings under CRP’s credit facility or otherwise will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes,prevailing commodity prices and differentials to NYMEX prices forother macroeconomic factors outside of our oil and natural gas production will be the largest variables affecting our working capital.control.

Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2017 (Successor) and September 30, 2016(Predecessor)
The following table summarizes our cash flows for the periods indicated:
Six Months Ended June 30,
(in thousands)20232022
Net cash provided by operating activities$886,704 $455,099 
Net cash used in investing activities(699,386)(228,603)
Net cash provided by (used in) financing activities(238,401)(34,784)
 Successor  Predecessor
(in thousands)For the Nine Months Ended September 30, 2017  For the Nine Months Ended September 30, 2016
Net cash provided by operating activities$137,150
  $51,511
Net cash used in investing activities(766,754)  (100,975)
Net cash provided by financing activities498,102
  48,106
DuringFor the ninesix months ended SeptemberJune 30, 2017,2023, we generated $137.2$886.7 million of cash provided byfrom operating activities, an increase of $85.6$431.6 million from the same period in 2016.2022. Cash provided by operating activities increased primarily due to higher net income as a results of increased crude oil, natural gas and NGL production volumes, lower GP&T expenses, higher cash settlements on derivatives and higher realized sales pricesthe timing of our receivable collections for gas and NGLs as well as lower cash interest paid during the ninesix months ended SeptemberJune 30, 2017.2023 as compared to the same 2022 period. These positiveincreasing factors were partially offset by lower realized prices for all commodities, higher lease operating expenses, severance and ad valorem taxes, GP&T expenses, exploration costs,merger and integration expense, and cash G&A expenses duringas well as the ninetiming of our supplier payments for the six months ended SeptemberJune 30, 20172023 as
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compared to the same period in 2016.2022 period. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and for more information on increases and decreasesfluctuations in certain expensesour operating costs between periods.
During the ninesix months ended SeptemberJune 30, 2017,2023, cash flows from operating activities, cash on hand, and $130.0 million of net borrowings under our credit facility were used to finance $354.5 million of drilling and development expenditures, while $333.5 million in netsales proceeds from the issuance of Class A common shares together with cash on hand, $35.0contingent consideration of $124.0 million in net borrowings under our credit facility, and proceeds from the sale of oil and natural gas properties were used to finance $419.5fund $686.6 million inof drilling and development cash expenditures, repay net borrowings of $85 million under our Credit Agreement, fund acquisitions of oil and gas property acquisitions.properties of $107.8 million, pay total cash dividends and distributions to noncontrolling interest owners of $85.5 million, repurchase $29.4 million of shares and purchase an office building in Midland, Texas for $27.5 million.
RevolvingDuring the six months ended June 30, 2022, cash flows from operating activities were used to finance $224.0 million of drilling and development cash expenditures and repay net borrowings of $25.0 million under our Credit FacilityAgreement.
CRPCredit Agreement
OpCo, our consolidated subsidiary, has a credit agreementCredit Agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing in February 2027 that as of SeptemberJune 30, 2017,2023, had a borrowing base of $350.0 million, which has been committed by lenders$2.5 billion and is available for borrowing. A portionelected commitments of the revolving credit facility in an aggregate amount not to exceed $15.0 million may be used to issue letters of credit for the account of CRP or other designated subsidiaries of the Company.$1.5 billion. As of SeptemberJune 30, 2017, the Company2023, we had $184.1$300 million of borrowings outstanding and $1.2 billion in available borrowing capacity, which was net of $165.0 million in borrowings and $0.9$5.8 million in letters of credit outstanding.
On April 24, 2023, we entered into the Third Amendment to the Credit Agreement. The amount available to be borrowed under CRP's revolving credit facility is subject to a borrowing base that is redetermined semiannually each April 1 and October 1 by the lenders in their sole discretion. CRP's credit agreement also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on,Third Amendment, among other things, the volumes of CRP's proved oil and natural gas reserves, estimated cash flows from these reserves and its commodity hedge positions. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of permitted issued senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of(i) reaffirmed the borrowing base if borrowingsat $2.5 billion and maintained the elected commitments at $1.5 billion; (ii) expanded the exceptions to the negative covenants to permit the incurrence of additional indebtedness on a pari passu basis with the facilities in excessthe Credit Agreement, subject to certain conditions; and (iii) made technical changes to permit OpCo to potentially incur term loans in addition to the revolving loans provided under the Credit Agreement, subject to terms to be agreed with the lenders making such term loans and to the terms of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under its credit agreement. In connection with the October 2017 semi-annual redetermination, on November 2, 2017, the Company entered into the fifth amendment to the restated credit agreement to increase the borrowing base from $350.0 million to $575.0 million.Credit Agreement.
Borrowings under CRP’s revolving credit facility may be base rate loans or LIBOR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for LIBOR loans. LIBOR loans bear interest at LIBOR (adjusted for statutory reserve requirements) plus an applicable margin ranging from 225 to 325 basis points, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR 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. At September 30, 2017, the weighted average interest rate on borrowings under CRP’s revolving credit facility was approximately 3.86%. CRP also pays a commitment fee on unused amounts of its revolving credit facility of 50 basis points. CRP may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. The credit facility provides for interest only payments until October 2019, when the credit agreement expires and all outstanding borrowings are due.
CRP’s credit agreementCredit Agreement contains restrictive covenants that limit itsour ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or declare dividends;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

our its outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates.
CRP’s credit agreementThe Credit Agreement also requires itOpCo to maintain compliance with the following financial ratios:
(i) a current ratio, which is the ratio of CRP’sOpCo’s consolidated current assets (including an add back of unused commitments under itsthe revolving credit facility and excluding non-cash derivative assets under ASC 815 and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under our credit agreementthe Credit Agreement and non-cash liabilities under ASC 815)derivative liabilities), of not less than 1.0 to 1.0; and
(ii) a leverage ratio, which isas defined within the Credit Agreement as the ratio of Total Funded Debt (as defined in CRP’s credit agreement)total funded debt to consolidated EBITDAX (as defined in CRP’s credit agreement)within the Credit Agreement) for the rolling four fiscalmost recent quarter period ending on such day,annualized, of not greater than 4.03.5 to 1.0.
CRPThe Credit Agreement includes fall away covenants, lower interest rates and reduced collateral requirements that OpCo may elect if OpCo is assigned an Investment Grade Rating (as defined within the Credit Agreement). OpCo was in compliance with the covenants and the applicable financial ratios described above as of SeptemberJune 30, 20172023 and through the filing of this report.Quarterly Report. For further information on the Credit Agreement, refer to Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report.
Off-Balance Sheet ArrangementsConvertible Senior Notes
AsOn March 19, 2021, OpCo issued $150.0 million of 3.25% senior unsecured convertible notes due 2028 (the “Convertible Senior Notes”). On March 26, 2021, OpCo issued an additional $20.0 million of Convertible Senior Notes pursuant to the exercise of the underwriters’ over-allotment option to purchase additional notes. These issuances resulted in aggregate net proceeds to OpCo of $163.6 million, which were used to repay borrowings outstanding under the Credit Agreement and to fund the cost of entering into capped call spread transactions of $14.7 million. Subsequently in April 2021, we redeemed at par all of our Senior Secured Notes (defined below), which was the intended use of proceeds from the Convertible Senior Notes offering.
The Convertible Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of OpCo’s current subsidiaries that guarantee OpCo’s outstanding Senior Unsecured Notes as defined below.
The Convertible Senior Notes bear interest at an annual rate of 3.25% and are due on April 1, 2028 unless earlier repurchased, redeemed or converted. The Convertible Senior Notes may become convertible prior to April 1, 2028, upon the occurrence of certain events or conditions being met as disclosed in Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report. OpCo can settle the Convertible Senior Notes by paying or delivering cash, shares of the Class A Common Stock, or a combination of cash and Class A Common Stock, at OpCo’s election.
In connection with the Convertible Senior Notes issuance, OpCo entered into privately negotiated capped call spread
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transactions (the “Capped Call Transactions”), that are expected to reduce potential dilution to our Class A Common Stock upon a conversion and/or offset any cash payments OpCo 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 Class A Common Stock and an initial capped price of $8.4525 per share of Class A Common Stock (each subject to certain customary adjustments).
Senior Notes
On September 1, 2022, in connection with the Merger, OpCo entered into supplemental indentures whereby all of Colgate’s outstanding senior notes were assumed at the Merger closing date and became the senior unsecured debt of OpCo. The senior notes assumed by OpCo included $300 million of 7.75% senior notes due 2026 (the “2026 7.75% Senior Notes”) and $700 million of 5.875% senior notes due 2029 (the “2029 Senior Notes”). The Company recorded the acquired senior notes at their fair value as of the Merger closing, which were equal to 100% of par for the 2026 7.75% Senior Notes and 93.68% of par (a $44.3 million debt discount) for the 2029 Senior Notes.
On November 30, 2017, OpCo issued $400.0 million of 5.375% senior notes due 2026 (the “2026 5.375% Senior Notes”) and on March 15, 2019, OpCo issued $500.0 million of 6.875% senior notes due 2027 (the “2027 Senior Notes” and, together with the 2026 5.375% Senior Notes, the 2029 Senior Notes and the 2026 7.75% Senior Notes, the “Senior Unsecured Notes”) in 144A private placements. In May 2020, $110.6 million aggregate principal amount of the 2026 5.375% Senior Notes and $143.7 million aggregate principal amount of the 2027 Senior Notes were validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount of 8.00% second lien senior secured notes (the “Senior Secured Notes”). The Senior Secured Notes were fully redeemed at par in connection with the Convertible Senior Notes issuance during the second quarter of 2021.
The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of OpCo’s current subsidiaries that guarantee OpCo’s Credit Agreement.
The indentures governing the Senior Unsecured Notes contain covenants that, among other things and subject to certain exceptions and qualifications, limit OpCo’s ability and the ability of OpCo’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. OpCo was in compliance with these covenants as of June 30, 2023 and through the filing of this Quarterly Report.
For further information on our Convertible Senior Notes and Senior Unsecured Notes, refer to Note 4—Long-Term Debt under Part I, Item I of this Quarterly Report.
Contractual Obligations
Our contractual obligations include operating and transportation agreements, drilling rig contracts, office and equipment leases, asset retirement obligations, long-term debt obligations and cash interest expense on long-term debt obligations, which we had no off-balance sheet arrangements.routinely enter into, modify or extend. Since December 31, 2022, there have not been any significant, non-routine changes in our contractual obligations other than the ground lease agreement entered into as discussed in Note 1—Basis of Presentation and Summary of Significant Accounting Policies.
Critical Accounting Policies and Estimates
There have been no material changes during the nine months ended September 30, 2017 to the methodology applied by management for critical accounting policies previouslyas disclosed in our 2016 Annual Report. Please refer to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates in our 20162022 Annual Report for a discussion of our critical accounting policies and estimates.Report.
New Accounting Pronouncements
Please refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies under Part I, Item 1. of this quarterly report forThere were no significant new accounting matters.standards adopted or new accounting pronouncements that would have potential effects on us or our financial statements as of June 30, 2023.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk
We    The term “market risk” as it applies to our business refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates, and we are exposed to market risk including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our majorprimary market risk exposure is in the pricing that we receive for our oil, natural gas and NGLsNGL production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue for the foreseeable future. Based on our production for the first half of 2023, our oil and gas sales for the six months ended June 30, 2023 would have moved up or down $107.4 million for each 10% change in the future.oil prices per Bbl, $5.6 million for each 10% change in natural gas prices per Mcf, and $11.0 million for each 10% change in NGL prices per Bbl.
Due to this volatility, we have historically used, and we expectmay elect to continue to opportunisticallyselectively use, commodity derivative instruments such(such as collars, swaps collars and basis swaps,swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flowflows that can emanate from operations due to fluctuations in oil and natural gas prices, and thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, and maybut alternatively they partially limit our potential gains from future increases in prices. CRP’s credit agreementOur Credit Agreement limits itsour ability to enter into commodity hedges covering greater than 80%85% of itsour reasonably anticipated projected production volume.from proved properties.
The following table below summarizes the approximate volumes and average contract pricesterms of swapthe derivative contracts the Companywe had in place as of SeptemberJune 30, 2017:2023 and additional contracts entered into through July 31, 2023. Refer to Note 7—Derivative Instruments in Part I, Item 1 of this Quarterly Report for open derivative positions as of June 30, 2023.
PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Crude Price
($/Bbl)(1)
Crude oil swapsJuly 2023 - September 20231,748,000 19,000 $85.04
October 2023 - December 20231,748,000 19,000 82.93
January 2024 - March 20241,547,000 17,000 77.14
April 2024 - June 20241,547,000 17,000 75.99
July 2024 - September 20241,564,000 17,000 74.89
October 2024 - December 20241,564,000 17,000 73.94
January 2025 - March 2025450,000 5,000 69.56
April 2025 - June 2025455,000 5,000 68.49
July 2025 - September 2025460,000 5,000 67.46
October 2025 - December 2025460,000 5,000 66.54
PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Collar Price Ranges
($/Bbl)(2)
Crude oil collarsJuly 2023 - September 2023644,000 7,000 $76.43-$92.70
October 2023 - December 2023644,000 7,000 76.43-92.70
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Description & Production PeriodVolume (Bbl) 
Weighted Average Fixed Price/Differential ($/Bbl) (1)
Crude Oil Swaps:   
October 2017 - December 201723,000
 $64.05
October 2017 - December 20179,200
 54.65
October 2017 - December 20179,200
 43.50
October 2017 - December 20179,200
 44.85
October 2017 - December 20179,200
 45.10
October 2017 - December 201727,600
 44.80
October 2017 - December 20179,200
 47.27
October 2017 - December 20179,200
 49.00
October 2017 - December 201746,000
 49.80
October 2017 - December 201718,400
 52.35
January 2018 - December 201836,500
 55.95
Crude Oil Basis Swaps:   
October 2017 - November 201715,250
 $(0.20)
October 2017 - November 20176,100
 (0.20)
PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(3)
Crude oil basis differential swapsJuly 2023 - September 20231,025,000 11,141 $0.63
October 2023 - December 20231,025,002 11,141 0.63
January 2024 - March 20241,092,000 12,000 0.66
April 2024 - June 20241,092,000 12,000 0.66
July 2024 - September 20241,104,000 12,000 0.66
October 2024 - December 20241,104,000 12,000 0.66
January 2025 - March 2025450,000 5,000 0.95
April 2025 - June 2025455,000 5,000 0.95
July 2025 - September 2025460,000 5,000 0.95
October 2025 - December 2025460,000 5,000 0.95
PeriodVolume (Bbls)Volume
(Bbls/d)
Wtd. Avg. Differential
($/Bbl)(4)
Crude oil roll differential swapsJuly 2023 - September 20231,656,000 18,000 $1.16
October 2023 - December 20231,656,000 18,000 1.16
January 2024 - March 20241,092,000 12,000 0.68
April 2024 - June 20241,092,000 12,000 0.67
July 2024 - September 20241,104,000 12,000 0.66
October 2024 - December 20241,104,000 12,000 0.66
January 2025 - March 2025180,000 2,000 0.37
April 2025 - June 2025182,000 2,000 0.37
July 2025 - September 2025184,000 2,000 0.37
October 2025 - December 2025184,000 2,000 0.37
(1)    These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2)    These crude oil collars are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3)    These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices during each applicable monthly settlement period.
(4)    These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.
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PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Gas Price
($/MMBtu)(1)
Natural gas swapsJuly 2023 - September 20231,486,925 16,162 $4.70
October 2023 - December 20231,413,628 15,366 4.90
January 2024 - March 20244,104,919 45,109 3.77
April 2024 - June 2024446,321 4,905 3.93
July 2024 - September 2024429,388 4,667 4.01
October 2024 - December 2024413,899 4,499 4.32
PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Differential
($/MMBtu)(2)
Natural gas basis differential swapsJuly 2023 - September 20236,210,000 67,500 $(1.30)
October 2023 - December 20236,210,000 67,500 (1.30)
January 2024 - March 20243,640,000 40,000 (0.52)
April 2024 - June 20241,820,000 20,000 (0.67)
July 2024 - September 20241,840,000 20,000 (0.66)
October 2024 - December 20241,840,000 20,000 (0.64)
PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Differential
($/MMBtu)(3)
Natural gas basis differential swapsJuly 2023 - September 20231,840,000 20,000 $(0.30)
October 2023 - December 20231,840,000 20,000 (0.30)
January 2024 - March 20243,640,000 40,000 0.00
PeriodVolume (MMBtu)Volume (MMBtu/d)
Wtd. Avg. Collar Price Ranges
($/MMBtu)(4)
Natural gas collarsJuly 2023 - September 20236,563,075 71,338 $3.64-$7.52
October 2023 - December 20236,636,37272,134 3.66-8.22
January 2024 - March 20243,175,08134,891 3.36-9.44
April 2024 - June 20241,373,67915,095 3.00-6.45
July 2024 - September 20241,410,61215,333 3.00-6.52
October 2024 - December 20241,426,10115,501 3.25-7.30
(1)
The oil swap contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis swap contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period.

(1)    These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2)    These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas during each applicable monthly settlement period.
(3)    These natural gas basis swap contracts are settled based on the difference between the Houston Ship Channel (“HSC”) price and the NYMEX price of natural gas during each applicable monthly settlement period.
(4)    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.
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Description & Production PeriodVolume (MMBtu) 
Weighted Average Fixed Price/Differential ($/MMBtu) (1)
Natural Gas Swaps:   
October 2017 - December 2017368,000
 $2.94
Natural Gas Basis Swaps:   
January 2018 - December 20181,825,000
 $(0.43)
January 2019 - December 20191,825,000
 $(0.43)
Changes in the fair value of derivative contracts from December 31, 2022 to June 30, 2023, are presented below:
(in thousands)Commodity derivative asset (liability)
Net fair value of oil and gas derivative contracts outstanding as of December 31, 2022$114,466 
Commodity hedge contract settlement payments, net of any receipts(79,014)
Cash and non-cash mark-to-market gains on commodity hedge contracts(1)
75,113 
Net fair value of oil and gas derivative contracts outstanding as of June 30, 2023$110,565 
(1)
The natural gas swap contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas. The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and the NYMEX price of Natural Gas during the relevant calculation period.
The fair value of these commodity(1)    At inception, new derivative instruments at September 30, 2017 was a net asset of $0.2 million. contracts entered into by us have no intrinsic value.
A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of SeptemberJune 30, 20172023 would cause a $1.1$86.7 million increase or $88.0 million decrease, respectively, in this fair value liability,position, and a hypothetical upward or downward shift of 10% per McfMMBtu in the NYMEX forward curve for natural gas as of SeptemberJune 30, 20172023 would cause a $0.1$4.7 million increase or $5.1 million decrease respectively, in this same fair value liability.position.
Interest Rate Risk
At SeptemberOur ability to borrow and the rates offered by lenders can be adversely affected by deteriorations in the credit markets and/or downgrades in our credit rating. OpCo’s Credit Agreement interest rate is based on a SOFR spread, which exposes us to interest rate risk to the extent we have borrowings outstanding under our revolving credit facility.
As of June 30, 2017,2023, we had $165.0$300.0 million of debtborrowings outstanding under our revolving credit facility, with a weighted average interest rate of 3.86%7.0%. Interest is calculated under the terms of CRP’s credit agreement based on a LIBOR spread. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the assumed weighted average interest rate would be approximately $1.7$3.0 million per year. We do not currently have or intend to enter into any derivative arrangementshedge contracts to protect against fluctuations in interest rates applicable to our outstanding indebtedness.

The remaining long-term debt balance of $1.8 billion consists of our senior notes, which have fixed interest rates; therefore, this balance is not affected by interest rate movements. For additional information regarding our debt instruments, see Note 4—Long-Term Debt, in Part I, Item 1 of this Quarterly Report.

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Item 4. Controls and Procedures
Evaluation of Disclosure Control and Procedures
In accordance with Rules 13a-15 and 15d-15 under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officerofficers and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of SeptemberJune 30, 2017.2023. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officerofficers and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officerofficers and principal financial officer concluded that our disclosure controls and procedures were effective as of SeptemberJune 30, 20172023 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There have not been anywere no changes in ourthe system of internal control over financial reporting that occurred(as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) during the threesix months ended SeptemberJune 30, 20172023 that have materially affected, or are reasonably likely to materially affect, ourthe Company’s internal controlscontrol over financial reporting.



PART II.  OTHER INFORMATION

Item 1. Legal Proceedings.Proceedings
From timeRefer to time,Note 12—Commitments and Contingencies under Part I, Item 1 of this Quarterly Report for more information regarding our legal proceedings.
Environmental. Due to the nature of the oil and gas industry, we are partyexposed to ongoing legal proceedingsenvironmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination and we conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from events are probable and the ordinary coursecosts can be reasonably estimated. Except as discussed herein, we are not aware of business, including workers’ compensationany material environmental claims and employment related disputes. While the outcomeexisting as of these proceedings cannot be predicted with certainty, we doJune 30, 2023 which have not believe the results of these proceedings, individuallybeen provided for or in the aggregate, willwould otherwise have a material adverse effectimpact on our business, financial condition, resultsstatements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties.
In the third quarter of operations or liquidity.2023, we entered into a Stipulated Final Order (the “Order”) to resolve a flaring violation detected by the Oil Conservation Division (“OCD”) in the State of New Mexico. To resolve the alleged violations, the OCD and Permian Resources jointly agreed to the Order, which assessed penalties in the amount of $600,000. We have implemented programs to meet the requirements of the OCD and are in the process of correcting any identified deficiencies.
Item 1A. Risk Factors.Factors
In addition to the other information set forth in this report,Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our 20162022 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our businesses, financial condition, or future results.filings. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 20162022 Annual Report or our other SEC filings.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
During the three months ended June 30, 2023, we did not purchase any Common Stock in the open market under the previously announced stock repurchase program.
Item 5. Other Information
Trading Plans
None of the Company’s directors or officers (as defined in Rule 16-a-1(f) of the Securities Exchange Act of 1934) adopted, terminated, or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement during the Company’s fiscal quarter ended June 30, 2023.
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Leadership Change
On August 2, 2023, the Company announced that Matt Garrison will be departing from his role as Chief Operating Officer for personal reasons, effective September 1, 2023. The Company does not intend to fill the Chief Operating Officer role, and Mr. Garrison’s direct operational reports will thereafter report to Will Hickey, the Company’s Co-CEO. Mr. Garrison’s decision to resign was not the result of any disagreement with the Company on any matter relating to the Company’s operations, policies or practices.
In connection with his resignation, Mr. Garrison will receive a prorated 2023 target cash bonus of approximately $290,000, an accelerated vesting of 165,033 shares of restricted stock and the retention of 202,605 performance restricted stock units that will be eligible to vest in the future based on Company performance. His remaining 218,773 performance restricted stock units will be forfeited in connection with his resignation.
The Company is also announcing that Brent Jensen, Senior Vice President and Chief Accounting Officer of the Company, plans to retire from the Company on November 30, 2023 and that Robert Shannon will succeed Mr. Jensen as the Company’s Chief Accounting Officer. Mr. Shannon currently serves as the Company’s Executive Vice President of Corporate Services, a role he has held since September 2022. Previously, Mr. Shannon served as Vice President and Chief Accounting Officer of Colgate Energy since March 2016. Mr. Jensen’s decision to retire was not the result of any disagreement with the Company on any matter relating to the Company’s operations, policies or practices.

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Item 6. Exhibits.
Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior SEC filing as indicated.
Exhibit

Number		Description of Exhibit
3.110.1Second
3.210.2#Amended and Restated Bylaws
3.331.1*Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC dated as of October 11, 2016 (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed with the SEC on October 11, 2016).
3.4Amendment No. 1 to Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC dated as of December 28, 2016 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on December 29, 2016).
3.5Amendment No. 2 to Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC dated as of March 20, 2017 (incorporated by reference to Exhibit 3.5 to the Registrant’s Annual Report on Form 10-K filed with the SEC on March 23, 2017).
31.1*
31.2*
31.3*
32.1*
32.2*
101.INS*Inline XBRL Instance Document.Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH*Inline XBRL Taxonomy Extension Schema Document.
101.CAL*Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*Inline XBRL Taxonomy Extension Presentation Linkbase Document.

#    Management contract or compensatory plan or agreement.

*    Filed herewith.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.
PERMIAN RESOURCES CORPORATION
CENTENNIAL RESOURCE DEVELOPMENT, INC.By:/s/ GUY M. OLIPHINT
By:/s/ GEORGE S. GLYPHIS
George S. GlyphisGuy M. Oliphint
Executive Vice President and Chief Financial Officer Treasurer and Assistant Secretary (Principal Financial Officer)
Date:November 6, 2017August 3, 2023



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