Permian Resources Corp - Quarter Report: 2023 June (Form 10-Q)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 2023
OR
☐ Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to
Commission file number 001-37697
PERMIAN RESOURCES CORPORATION
(Exact Name of Registrant as Specified in its Charter)
| Delaware | 47-5381253 | |||||||
| (State of Incorporation) | (I.R.S. Employer Identification No.) | |||||||
300 N. Marienfeld St., Suite 1000
Midland, Texas 79701
(Registrant’s telephone number, including area code): (432) 695-4222
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol | Name of each exchange on which registered | ||||||||||||
| Class A Common Stock, par value $0.0001 per share | PR | New 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 ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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. ☐
| Large accelerated filer | Accelerated filer | Non-accelerated filer | Smaller reporting company | Emerging growth company | ||||||||||||||||||||||
☒ | ☐ | ☐ | ☐ | ☐ | ||||||||||||||||||||||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
As of July 31, 2023, there were 565,955,410 shares of total common stock outstanding, including 321,327,851 shares of Class A Common Stock, par value $0.0001 per share, and 244,627,559 shares of Class C Common Stock, par value $0.0001 per share.
TABLE OF CONTENTS
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GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS
The following are abbreviations and definitions of certain terms used in this Quarterly Report on Form 10-Q, which are commonly used in the oil and natural gas industry:
Bbl. One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.
Bbl/d. One Bbl per day.
Boe. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
Boe/d. One Boe per day.
Btu. One British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one-degree Fahrenheit.
Completion. The process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to initiate production.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality, gathering, processing and transportation fees and location of oil or natural gas.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Extension well. A well drilled to extend the limits of a known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Formation. A layer of rock which has distinct characteristics that differs from nearby rock.
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).
MBbl. One thousand barrels of crude oil, condensate or NGLs.
MBoe. One thousand Boe.
Mcf. One thousand cubic feet of natural gas.
Mcf/d. One Mcf per day.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of natural gas.
NGL. Natural gas liquids. These are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline, that can be collectively removed from produced natural gas, separated 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 differentials.
Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty interest. An interest in an oil or gas property entitling the owner to shares of the production free of costs of exploration, development and production operations.
SOFR. Secured Overnight Funding Rate.
Spot market price. The cash market price without reduction for expected quality, location, transportation and demand adjustments.
Unproved reserves. Reserves attributable to unproved properties with no proved reserves.
Wellbore. The hole drilled by a drill bit that is equipped for oil and natural gas production once the well has been completed. Also called well or borehole.
Working interest. The interest in an oil and gas property (typically a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.
Workover. Operations on a producing well to restore or increase production.
WTI. West Texas Intermediate is a grade of crude oil used as a benchmark in oil pricing.
4
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (“Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,” “plan,” “target” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under Item 1A. Risk Factors in this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, 2022 (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 and future drilling plans;
•our reserves and our ability to replace the reserves we produce through drilling and property acquisitions;
•our drilling prospects, inventories, projects and programs;
•our financial strategy, 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 competition and government regulations;
•our ability to obtain permits and governmental approvals;
•our pending legal or environmental matters;
•the marketing and transportation of our oil, natural gas and NGLs;
•our leasehold or business acquisitions;
•cost of developing or operating our properties;
•our anticipated rate of return;
•general economic conditions;
•weather conditions in the areas where we operate;
•credit markets;
•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 Quarterly Report that are not historical.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to commodity price volatility, inflation, lack of availability of drilling and production equipment and services, 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 in “Item 1A. Risk Factors” in this Quarterly Report and our 2022 Annual Report.
Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties described in this Quarterly Report or our 2022 Annual Report occur, or underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statement in this section, to reflect events or circumstances after the date of this Quarterly Report.
6
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
PERMIAN RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS (unaudited)
(in thousands, except share and per share amounts)
| June 30, 2023 | December 31, 2022 | ||||||||||
ASSETS | |||||||||||
Current assets | |||||||||||
Cash and cash equivalents | $ | 18,280 | $ | 59,545 | |||||||
Accounts receivable, net | 309,624 | 282,846 | |||||||||
| Derivative instruments | 87,737 | 100,797 | |||||||||
Prepaid and other current assets | 10,396 | 20,602 | |||||||||
Total current assets | 426,037 | 463,790 | |||||||||
Property and Equipment | |||||||||||
Oil and natural gas properties, successful efforts method | |||||||||||
Unproved properties | 1,415,969 | 1,424,744 | |||||||||
Proved properties | 9,691,058 | 8,869,174 | |||||||||
Accumulated depreciation, depletion and amortization | (2,811,580) | (2,419,692) | |||||||||
Total oil and natural gas properties, net | 8,295,447 | 7,874,226 | |||||||||
| Other property and equipment, net | 38,731 | 15,173 | |||||||||
Total property and equipment, net | 8,334,178 | 7,889,399 | |||||||||
Noncurrent assets | |||||||||||
Operating lease right-of-use assets | 62,049 | 64,792 | |||||||||
Other noncurrent assets | 104,061 | 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 liabilities | 36,160 | 29,759 | |||||||||
| Derivative instruments | 354 | 1,998 | |||||||||
Other current liabilities | 24,462 | 11,656 | |||||||||
Total current liabilities | 722,724 | 605,569 | |||||||||
Noncurrent liabilities | |||||||||||
| Long-term debt, net | 2,060,070 | 2,140,798 | |||||||||
| Asset retirement obligations | 44,546 | 40,947 | |||||||||
| Deferred income taxes | 78,685 | 4,430 | |||||||||
| Operating lease liabilities | 27,894 | 41,341 | |||||||||
Other noncurrent liabilities | 66,396 | 3,211 | |||||||||
Total liabilities | 3,000,315 | 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, 2022 | 33 | 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, 2022 | 24 | 27 | |||||||||
| Additional paid-in capital | 2,944,785 | 2,698,465 | |||||||||
| Retained earnings (accumulated deficit) | 363,881 | 237,226 | |||||||||
| Total shareholders' equity | 3,308,723 | 2,935,748 | |||||||||
| Noncontrolling interest | 2,617,287 | 2,720,548 | |||||||||
| Total equity | 5,926,010 | 5,656,296 | |||||||||
| TOTAL LIABILITIES AND EQUITY | $ | 8,926,325 | $ | 8,492,592 | |||||||
The accompanying notes are an integral part of these unaudited consolidated financial statements.
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PERMIAN RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
(in thousands, except per share data)
(in thousands, except per share data)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
Operating revenues | |||||||||||||||||||||||
| Oil and gas sales | $ | 623,398 | $ | 472,654 | $ | 1,239,666 | $ | 819,931 | |||||||||||||||
| Operating expenses | |||||||||||||||||||||||
| Lease operating expenses | 82,991 | 28,900 | 157,523 | 57,634 | |||||||||||||||||||
| Severance and ad valorem taxes | 48,927 | 34,695 | 97,436 | 59,746 | |||||||||||||||||||
| Gathering, processing and transportation expenses | 21,753 | 25,756 | 37,235 | 47,647 | |||||||||||||||||||
| Depreciation, depletion and amortization | 215,726 | 82,117 | 403,945 | 153,126 | |||||||||||||||||||
| General and administrative expenses | 52,736 | 9,947 | 88,210 | 40,550 | |||||||||||||||||||
| Merger and integration expense | 4,350 | 5,685 | 17,649 | 5,685 | |||||||||||||||||||
| Impairment and abandonment expense | 244 | 506 | 489 | 3,133 | |||||||||||||||||||
| Exploration and other expenses | 5,263 | 1,954 | 9,637 | 4,261 | |||||||||||||||||||
| Total operating expenses | 431,990 | 189,560 | 812,124 | 371,782 | |||||||||||||||||||
| Net gain (loss) on sale of long-lived assets | — | (1,406) | 66 | (1,324) | |||||||||||||||||||
| Income (loss) from operations | 191,408 | 281,688 | 427,608 | 446,825 | |||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||
| Interest expense | (36,826) | (14,326) | (73,603) | (27,480) | |||||||||||||||||||
| Net gain (loss) on derivative instruments | 20,601 | (34,134) | 75,113 | (163,657) | |||||||||||||||||||
| Other income (expense) | 319 | 85 | 439 | 203 | |||||||||||||||||||
Total other income (expense) | (15,906) | (48,375) | 1,949 | (190,934) | |||||||||||||||||||
| Income (loss) before income taxes | 175,502 | 233,313 | 429,557 | 255,891 | |||||||||||||||||||
| Income tax (expense) benefit | (26,548) | (41,487) | (60,802) | (48,263) | |||||||||||||||||||
| Net income (loss) | 148,954 | 191,826 | 368,755 | 207,628 | |||||||||||||||||||
| Less: Net (income) loss attributable to noncontrolling interest | (75,555) | — | (193,236) | — | |||||||||||||||||||
| Net 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: | |||||||||||||||||||||||
| Basic | $ | 0.23 | $ | 0.67 | $ | 0.57 | $ | 0.73 | |||||||||||||||
| Diluted | $ | 0.21 | $ | 0.60 | $ | 0.52 | $ | 0.66 | |||||||||||||||
The accompanying notes are an integral part of these unaudited consolidated financial statements.
8
PERMIAN RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(in thousands)
(in thousands)
| 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 amortization | 403,945 | 153,126 | |||||||||
Stock-based compensation expense - equity awards | 53,565 | 12,202 | |||||||||
| Stock-based compensation expense - liability awards | — | 5,127 | |||||||||
Impairment and abandonment expense | 489 | 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) loss | 3,901 | 47,131 | |||||||||
| Amortization of debt issuance costs and debt discount | 6,278 | 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 liabilities | 8,495 | 42,491 | |||||||||
| Net cash provided by operating activities | 886,704 | 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 divestiture | 60,000 | — | |||||||||
Proceeds from sales of oil and natural gas properties | 63,986 | 863 | |||||||||
| Net cash used in investing activities | (699,386) | (228,603) | |||||||||
Cash flows from financing activities: | |||||||||||
Proceeds from borrowings under revolving credit facility | 630,000 | 170,000 | |||||||||
Repayment of borrowings under revolving credit facility | (715,000) | (195,000) | |||||||||
Debt issuance costs | (603) | (8,533) | |||||||||
Proceeds from exercise of stock options | 230 | 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 period | 69,932 | 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 consolidated financial statements.
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PERMIAN RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (continued)
(in thousands)
(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 taxes | 3,603 | 600 | |||||||||
Supplemental non-cash activity | |||||||||||
Accrued capital expenditures included in accounts payable and accrued expenses | 242,782 | 63,486 | |||||||||
| Deferred tax liability assumed in asset acquisition | 24,801 | — | |||||||||
Asset retirement obligations incurred, including revisions to estimates | 1,207 | 389 | |||||||||
| Dividends payable | 2,302 | — | |||||||||
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, | |||||||||||
| 2023 | 2022 | ||||||||||
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 consolidated financial statements.
10
PERMIAN RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)
(in thousands)
| Common Stock | Additional Paid-In Capital | Retained Earnings (Accumulated Deficit) | Total Shareholders’ Equity | Non-controlling Interest | Total Equity | ||||||||||||||||||||||||||||||||||||||||||||||||
| Class A | Class C | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2022 | 298,640 | $ | 30 | 269,300 | $ | 27 | $ | 2,698,465 | $ | 237,226 | $ | 2,935,748 | $ | 2,720,548 | $ | 5,656,296 | |||||||||||||||||||||||||||||||||||||
| Restricted stock issued | 359 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock forfeited | (298) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Stock purchased from employees for taxes due upon share vesting | (3,384) | — | — | — | (32,160) | — | (32,160) | — | (32,160) | ||||||||||||||||||||||||||||||||||||||||||||
| Stock option exercises | 39 | — | — | — | 231 | — | 231 | — | 231 | ||||||||||||||||||||||||||||||||||||||||||||
| Issuance of Common Stock under Employee Stock Purchase Plan | 56 | — | — | — | 241 | — | 241 | — | 241 | ||||||||||||||||||||||||||||||||||||||||||||
| Performance stock vested and issued | 5,406 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| 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 tax | 20,906 | 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, 2023 | 321,724 | $ | 32 | 245,644 | $ | 25 | $ | 2,891,528 | $ | 323,677 | $ | 3,215,262 | $ | 2,593,424 | $ | 5,808,686 | |||||||||||||||||||||||||||||||||||||
| Restricted stock issued | 373 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock forfeited | (357) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Stock purchased from employees for taxes due upon share vesting | (602) | (1) | — | — | (5,948) | — | (5,949) | — | (5,949) | ||||||||||||||||||||||||||||||||||||||||||||
| Stock option exercises | 7 | — | — | — | (1) | — | (1) | — | (1) | ||||||||||||||||||||||||||||||||||||||||||||
| Performance stock vested and issued | 3,290 | 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 tax | 1,011 | 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, 2023 | 325,446 | $ | 33 | 244,633 | $ | 24 | $ | 2,944,785 | $ | 363,881 | $ | 3,308,723 | $ | 2,617,287 | $ | 5,926,010 | |||||||||||||||||||||||||||||||||||||
11
PERMIAN RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited) (continued)
(in thousands)
| Common Stock | Additional Paid-In Capital | Retained Earnings (Accumulated Deficit) | Total Shareholders’ Equity | Non-controlling Interest | Total Equity | ||||||||||||||||||||||||||||||||||||||||||||||||
| Class A | Class C | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | 294,261 | $ | 29 | — | $ | — | $ | 3,013,017 | $ | (262,326) | $ | 2,750,720 | $ | — | $ | 2,750,720 | |||||||||||||||||||||||||||||||||||||
| Restricted stock issued | 20 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock forfeited | (52) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Stock purchased from employees for taxes due upon share vesting | (150) | — | — | — | (1,259) | — | (1,259) | — | (1,259) | ||||||||||||||||||||||||||||||||||||||||||||
| Stock option exercises | 3 | — | — | — | 1 | — | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||
| Issuance of Common Stock under Employee Stock Purchase Plan | 53 | — | — | — | 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, 2022 | 294,135 | $ | 29 | — | $ | — | $ | 3,017,572 | $ | (246,524) | $ | 2,771,077 | $ | — | $ | 2,771,077 | |||||||||||||||||||||||||||||||||||||
| Restricted stock issued | 2,998 | 1 | — | — | — | — | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock forfeited | (75) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Stock option exercises | 2 | — | — | — | 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, 2022 | 297,060 | $ | 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.
12
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1—Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Permian Resources Corporation is an independent oil and natural gas 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 “Permian Resources” or the “Company” are to Permian Resources Corporation and its consolidated subsidiary, Permian Resources Operating, LLC (“OpCo”).
Principles of Consolidation and Basis of Presentation
The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and the rules and regulations of the United States Securities and Exchange Commission (“SEC”) for interim financial reporting. Accordingly, certain disclosures normally included in an Annual Report on Form 10-K have been omitted. The consolidated financial statements and related notes included in this Quarterly Report should be read in conjunction with the Company’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the period ended December 31, 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 to present fairly, in all material respects, the Company’s interim financial results have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. The consolidated financial statements include the accounts of the Company and its subsidiary OpCo, and OpCo’s wholly-owned subsidiaries. Noncontrolling interest represents third-party ownership in OpCo and 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 the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events, and accordingly, actual results could differ from amounts previously established. Additionally, the prices received for oil, natural gas and NGL production can heavily influence the Company’s assumptions, judgments and estimates and continued volatility of oil and gas prices could have a significant impact on the Company’s estimates.
The more significant areas requiring the use of assumptions, judgments and estimates include: (i) oil and natural gas reserves; (ii) cash flow estimates used in impairment tests for long-lived assets; (iii) impairment expense of unproved properties; (iv) depreciation, depletion and amortization; (v) asset retirement obligations; (vi) determining fair value and allocating purchase price in connection with business combinations and asset acquisitions; (vii) accrued revenues and related receivables; (viii) accrued liabilities; (ix) derivative valuations; (x) deferred income taxes; and (xi) determining the fair values of certain stock-based compensation awards.
Leases
The Company has operating leases for drilling rig contracts, office rental agreements and other wellhead equipment. During the 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 April 2023, the Company purchased an office building in Midland, Texas for $27.5 million, where it had previously been a lessee of the building at the time of purchase. As a result, $9.3 million of operating lease right-of-use assets and $13.6 million of operating lease liabilities were removed from the consolidated balance sheet as of June 30, 2023. As part of the building purchase, the Company assumed a ninety-nine year ground lease and accordingly, recorded a financing lease liability of $15.4 million as of June 30, 2023, which represents the present value of the future 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 $15.3 million as of June 30, 2023.
13
PERMIAN RESOURCES CORPORATION
NOTES TO 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 Classification | June 30, 2023 | December 31, 2022 | ||||||||||||||
| Assets | |||||||||||||||||
| Operating right-of-use assets | Operating lease right-of-use asset | $ | 62,049 | $ | 64,792 | ||||||||||||
| Finance right-of-use asset | Other noncurrent assets | 15,267 | — | ||||||||||||||
| Liabilities | |||||||||||||||||
| Current | |||||||||||||||||
| Operating lease liabilities | Operating lease liabilities | $ | 36,160 | $ | 29,759 | ||||||||||||
| Finance lease liability | Other current liabilities | 744 | — | ||||||||||||||
| Noncurrent | |||||||||||||||||
| Operating lease liabilities | Operating lease liabilities | $ | 27,894 | $ | 41,341 | ||||||||||||
| Finance lease liability | Other noncurrent liabilities | 14,690 | — | ||||||||||||||
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 Company’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 any taxable income or loss of OpCo, as well as any stand-alone income or loss generated by the Company. As of the date of the 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 subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by OpCo is passed through to and included in the taxable income or loss of its members, including the Company, on a pro rata basis. Prior to the Merger, OpCo was fully owned by the Company and all income and loss was taxable.
Income tax expense recognized during interim periods is based on applying an estimated annual effective income tax rate to the Company’s year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various state jurisdictions, permanent and temporary differences and the likelihood of recovering deferred tax assets generated. The accounting estimates used to compute the provision for income taxes may change as new events occur, additional information becomes known or as the tax environment changes.
Note 2—Acquisitions and Divestitures
Colgate Merger
On September 1, 2022, the Company completed 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 Delaware Basin. Refer to Note 2—Business Combination footnote in the notes to the consolidated financial statements in Part II, Item 8 of the Company’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 assumed are not complete and adjustments may be made. The Company expects to complete the purchase 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 of the Merger. The following supplemental unaudited pro forma financial information (“pro forma information”) for the three and six months ended June 30, 2022 has been prepared from the respective historical consolidated financial statements of the Company and Colgate and has been adjusted to reflect the Merger as if it had occurred on January 1, 2022. The pro forma information reflects transaction accounting adjustments that the Company believes are factually supportable and that are expected to have a continuing impact on the results 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 to integrate the Colgate assets.
14
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The pro forma information is not necessarily indicative of the results 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, 2022 | Six 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 | |||||||
| Diluted | 0.58 | 0.35 | |||||||||
2023 Acquisition
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 future 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 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, 2023 | December 31, 2022 | |||||||||
Accrued oil and gas sales receivable, net | $ | 167,458 | $ | 206,266 | |||||||
Joint interest billings, net | 126,513 | 58,375 | |||||||||
Accrued derivative settlements receivable | 13,557 | 16,999 | |||||||||
Other | 2,096 | 1,206 | |||||||||
Accounts receivable, net | $ | 309,624 | $ | 282,846 | |||||||
15
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Accounts payable and accrued expenses are comprised of the following:
(in thousands) | June 30, 2023 | December 31, 2022 | |||||||||
Accounts payable | $ | 102,531 | $ | 51,443 | |||||||
Accrued capital expenditures | 178,213 | 133,854 | |||||||||
Revenues payable | 275,873 | 250,120 | |||||||||
Accrued employee compensation and benefits | 10,692 | 33,897 | |||||||||
Accrued interest | 45,376 | 45,627 | |||||||||
Accrued derivative settlements payable | — | 2,342 | |||||||||
Accrued expenses and other | 49,063 | 44,873 | |||||||||
Accounts payable and accrued expenses | $ | 661,748 | $ | 562,156 | |||||||
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, 2023 | December 31, 2022 | |||||||||
Credit Facility due 2027 | $ | 300,000 | $ | 385,000 | |||||||
| Senior Notes | |||||||||||
5.375% Senior Notes due 2026 | 289,448 | 289,448 | |||||||||
7.75% Senior Notes due 2026 | 300,000 | 300,000 | |||||||||
6.875% Senior Notes due 2027 | 356,351 | 356,351 | |||||||||
3.25% Convertible Senior Notes due 2028 | 170,000 | 170,000 | |||||||||
5.875% Senior Notes due 2029 | 700,000 | 700,000 | |||||||||
Unamortized debt issuance costs on Senior Notes | (9,804) | (10,994) | |||||||||
Unamortized debt discount | (45,925) | (49,007) | |||||||||
| Senior Notes, net | 1,760,070 | 1,755,798 | |||||||||
Total long-term debt, net | $ | 2,060,070 | $ | 2,140,798 | |||||||
Credit Agreement
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 June 30, 2023, had a borrowing base of $2.5 billion and elected commitments of $1.5 billion. As of June 30, 2023, the Company had $300 million of borrowings outstanding and $1.2 billion in available borrowing capacity, net of $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 the Credit Agreement is equal to the lesser of (i) the borrowing base, which 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 in the spring and fall by the lenders in their sole discretion. It also allows for two optional borrowing base redeterminations in between the scheduled redeterminations. The borrowing base depends on, among other things, the quantities of OpCo’s proved oil and natural gas reserves, estimated cash flows from those reserves, and the Company’s commodity hedge positions. Upon a redetermination of the borrowing base, if actual borrowings outstanding exceed the revised borrowing capacity, OpCo could be required to immediately repay a portion of its debt outstanding. Borrowings under the Credit Agreement are guaranteed by certain of OpCo’s subsidiaries, including entities that became subsidiaries of OpCo through the Merger.
16
PERMIAN RESOURCES CORPORATION
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 spread adjustment. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted Term SOFR rate for a one-month interest period plus 100 basis points, plus an applicable margin, ranging from 75 to 175 basis points, depending on the percentage of the borrowing base utilized. OpCo also pays a commitment fee of 37.5 to 50 basis points on unused elected commitment amounts under its facility.
The Credit Agreement contains restrictive covenants that limit our ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or redeem junior debt; (vi) enter into commodity hedges exceeding a specified percentage of our expected production; (vii) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates.
The Credit Agreement also requires OpCo to maintain compliance with the following financial ratios:
(i) a current ratio, which is the ratio of OpCo’s consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and
(ii) a leverage ratio, as defined within the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX (as defined within the Credit Agreement) for the most recent quarter annualized, of not greater than 3.5 to 1.0.
The 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.
17
PERMIAN RESOURCES CORPORATION
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.
18
PERMIAN RESOURCES CORPORATION
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 collectively with the 2027 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 $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.
19
PERMIAN RESOURCES CORPORATION
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 changes in the Company’s asset retirement obligations (“ARO”) associated with its working interests in oil and gas properties for the six months ended June 30, 2023:
(in thousands) | |||||
Asset retirement obligations, beginning of period | $ | 40,947 | |||
Liabilities incurred | 1,207 | ||||
| Liabilities acquired | 5,260 | ||||
Liabilities divested and settled | (4,270) | ||||
Accretion expense | 1,402 | ||||
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 gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. Inherent in the fair value calculation of ARO are numerous estimates and assumptions, including plug and abandonment settlement amounts, inflation factors, credit adjusted discount rates and timing of settlement. To the extent future revisions to these assumptions impact the value of the existing ARO liabilities, a corresponding offsetting adjustment is made to the oil and gas property balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability with an offsetting charge to accretion expense, which is included within depreciation, depletion and amortization.
Note 6—Stock-Based Compensation
On May 23, 2023, the stockholders of the Company approved the 2023 Long Term Incentive Plan (the “LTIP”). The LTIP is an equity incentive plan that replaced the Company’s prior plan, and, among other things, increased the number of shares of Class A Common Stock authorized for issuance to employees and directors by 25,000,000 shares to a total of 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 and other stock or cash-based awards.
Stock-based compensation expense is recognized within both General and administrative expenses and Exploration and other expenses in the consolidated statements of operations. The Company accounts for forfeitures of awards granted under the LTIP as they occur.
20
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table summarizes stock-based compensation expense recognized for the periods presented:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (in thousands) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Equity Awards | |||||||||||||||||||||||
| Restricted stock | $ | 13,340 | $ | 4,481 | $ | 24,013 | $ | 7,920 | |||||||||||||||
| Stock option awards | — | 26 | 1 | 57 | |||||||||||||||||||
| Performance stock units | 22,354 | 2,079 | 29,551 | 4,082 | |||||||||||||||||||
Other stock-based compensation expense(1) | — | 71 | — | 143 | |||||||||||||||||||
| Total stock-based compensation - equity awards | 35,694 | 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 activity during the six months ended June 30, 2023:
| Restricted Stock | Weighted Average Fair Value | ||||||||||
| Unvested balance as of December 31, 2022 | 8,182,705 | $ | 6.03 | ||||||||
| Granted | 731,782 | 9.79 | |||||||||
| Vested | (2,577,919) | 9.04 | |||||||||
| Forfeited | (536,675) | 7.64 | |||||||||
| Unvested balance as of June 30, 2023 | 5,799,893 | 6.73 | |||||||||
The Company grants service-based restricted stock to certain officers and employees, which either vests ratably over a three-year service period or cliff vests upon a five-year service period, and to directors, which vest over a one-year service period. Compensation cost for these service-based restricted stock grants is based on the closing market price of the Company’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 restricted shares that were unvested as of June 30, 2023 was $29.9 million, which the Company expects to recognize over a weighted average period of 2.3 years.
21
PERMIAN RESOURCES CORPORATION
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 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 on the grant date. Compensation cost for stock options is based on the grant-date fair value of the award, which is then recognized ratably over the vesting period of three years.
The following table provides information about stock option awards outstanding during the six months ended June 30, 2023:
| Options | Weighted Average Exercise Price | Weighted Average Remaining Term (in years) | Aggregate Intrinsic Value (in thousands) | ||||||||||||||||||||
| Outstanding as of December 31, 2022 | 2,056,467 | $ | 15.44 | ||||||||||||||||||||
| Granted | — | — | |||||||||||||||||||||
| Exercised | (46,834) | 4.98 | $ | 249 | |||||||||||||||||||
| Forfeited | — | — | |||||||||||||||||||||
| Expired | (614,334) | 15.23 | |||||||||||||||||||||
| Outstanding as of June 30, 2023 | 1,395,299 | 15.88 | 2.6 | $ | 455 | ||||||||||||||||||
| Exercisable as of June 30, 2023 | 1,395,299 | 15.88 | 2.6 | $ | 455 | ||||||||||||||||||
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 June 30, 2023, there was no unrecognized compensation cost related to unvested stock options.
Performance Stock Units
The Company grants performance stock units (“PSU”) to certain officers that are subject to market-based vesting criteria as well as a service period ranging from to five years. Vesting at the end of the service period depends on the Company’s absolute annualized total shareholder return (“TSR”) over the service period, as well as the Company’s TSR relative to the TSR of a peer group of companies. These market-based conditions must be met in order for the stock awards to vest, and it is therefore possible that no shares could ultimately vest. However, the Company recognizes compensation expense for the PSUs subject to market conditions regardless of whether it becomes probable that these conditions will be met or not, and compensation expense is not reversed if vesting does not actually occur.
The Company’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 values 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 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 vesting periods.
The following table summarizes the key assumptions and related information used to determine the fair value of PSUs granted during the six months ended June 30, 2023:
| 2023 Awards | ||||||||
| Number of PSUs granted | 237,097 | |||||||
| Weighted average fair value | $16.68 | |||||||
| Number of simulations | 10,000,000 | |||||||
| Expected implied stock volatility | 59.2% | |||||||
| Risk-free interest rate | 4.1% | |||||||
22
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table provides information about PSUs outstanding during the six months ended June 30, 2023:
| Awards | Weighted Average Fair Value | ||||||||||
| Unvested balance as of December 31, 2022 | 7,638,098 | $ | 13.11 | ||||||||
| Granted | 237,097 | 16.68 | |||||||||
Vested(1) | (1,624,895) | 9.74 | |||||||||
| Forfeited | (210,035) | 13.64 | |||||||||
| Unvested balance as of June 30, 2023 | 6,040,265 | 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.
The total fair value of PSUs that vested during the six months ended June 30, 2023 was $32.0 million. As of June 30, 2023, there was $56.7 million of unrecognized compensation cost related to PSUs that were unvested, which the Company expects to recognize on a pro-rata basis over a weighted average period of 2.7 years.
Liability Awards
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.
On August 18, 2022, the Compensation Committee amended the 2020 PSU agreement to allow a portion of the 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.
The remaining 0.8 million 2020 PSUs were accelerated vested and settled in a $9.4 million cash payment during the third quarter of 2022. There are no liability classified performance stock units outstanding as of June 30, 2023.
Note 7—Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations and may use derivative instruments to manage its exposure to commodity price risk from time to time.
Commodity Derivative Contracts
Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. The Company may periodically use derivative instruments, such as swaps, costless collars and basis swaps, to mitigate its exposure to declines in commodity prices and to the corresponding negative impacts such declines can have on its cash flows from operations, returns on capital and other financial results. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. The Company does not enter into derivative contracts for speculative or trading purposes.
Commodity Swap and Collar Contracts. The Company may use commodity derivative instruments known as fixed price swaps to realize a known price for a specific volume of production, basis swaps to hedge the difference between the index price and a local or future index price, or costless collars to establish fixed price floors and ceilings. All transactions are settled in cash with one party paying the other for the resulting difference in price multiplied by the contract volume.
23
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table summarizes the approximate volumes and average contract prices of derivative contracts the Company had in place as of June 30, 2023:
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Crude Price ($/Bbl)(1) | ||||||||||||||||||||
Crude oil swaps | July 2023 - September 2023 | 1,748,000 | 19,000 | $85.04 | |||||||||||||||||||
| October 2023 - December 2023 | 1,748,000 | 19,000 | 82.93 | ||||||||||||||||||||
| January 2024 - March 2024 | 1,547,000 | 17,000 | 77.14 | ||||||||||||||||||||
| April 2024 - June 2024 | 1,547,000 | 17,000 | 75.99 | ||||||||||||||||||||
| July 2024 - September 2024 | 1,564,000 | 17,000 | 74.89 | ||||||||||||||||||||
| October 2024 - December 2024 | 1,564,000 | 17,000 | 73.94 | ||||||||||||||||||||
| January 2025 - March 2025 | 450,000 | 5,000 | 69.56 | ||||||||||||||||||||
| April 2025 - June 2025 | 455,000 | 5,000 | 68.49 | ||||||||||||||||||||
| July 2025 - September 2025 | 460,000 | 5,000 | 67.46 | ||||||||||||||||||||
| October 2025 - December 2025 | 460,000 | 5,000 | 66.54 | ||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Collar Price Ranges ($/Bbl)(2) | ||||||||||||||||||||||||||
| Crude oil collars | July 2023 - September 2023 | 644,000 | 7,000 | $76.43 | - | $92.70 | |||||||||||||||||||||||
| October 2023 - December 2023 | 644,000 | 7,000 | 76.43 | - | 92.70 | ||||||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(3) | ||||||||||||||||||||
Crude oil basis differential swaps | July 2023 - September 2023 | 1,025,000 | 11,141 | $0.63 | |||||||||||||||||||
| October 2023 - December 2023 | 1,025,002 | 11,141 | 0.63 | ||||||||||||||||||||
| January 2024 - March 2024 | 1,092,000 | 12,000 | 0.66 | ||||||||||||||||||||
| April 2024 - June 2024 | 1,092,000 | 12,000 | 0.66 | ||||||||||||||||||||
| July 2024 - September 2024 | 1,104,000 | 12,000 | 0.66 | ||||||||||||||||||||
| October 2024 - December 2024 | 1,104,000 | 12,000 | 0.66 | ||||||||||||||||||||
| January 2025 - March 2025 | 450,000 | 5,000 | 0.95 | ||||||||||||||||||||
| April 2025 - June 2025 | 455,000 | 5,000 | 0.95 | ||||||||||||||||||||
| July 2025 - September 2025 | 460,000 | 5,000 | 0.95 | ||||||||||||||||||||
| October 2025 - December 2025 | 460,000 | 5,000 | 0.95 | ||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(4) | ||||||||||||||||||||
Crude oil roll differential swaps | July 2023 - September 2023 | 1,656,000 | 18,000 | $1.16 | |||||||||||||||||||
| October 2023 - December 2023 | 1,656,000 | 18,000 | 1.16 | ||||||||||||||||||||
| January 2024 - March 2024 | 1,092,000 | 12,000 | 0.68 | ||||||||||||||||||||
| April 2024 - June 2024 | 1,092,000 | 12,000 | 0.67 | ||||||||||||||||||||
| July 2024 - September 2024 | 1,104,000 | 12,000 | 0.66 | ||||||||||||||||||||
| October 2024 - December 2024 | 1,104,000 | 12,000 | 0.66 | ||||||||||||||||||||
| January 2025 - March 2025 | 180,000 | 2,000 | 0.37 | ||||||||||||||||||||
| April 2025 - June 2025 | 182,000 | 2,000 | 0.37 | ||||||||||||||||||||
| July 2025 - September 2025 | 184,000 | 2,000 | 0.37 | ||||||||||||||||||||
| October 2025 - December 2025 | 184,000 | 2,000 | 0.37 | ||||||||||||||||||||
(1) These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
24
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(2) These crude oil collars are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices during each applicable monthly settlement period.
(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Gas Price ($/MMBtu)(1) | ||||||||||||||||||||
Natural gas swaps | July 2023 - September 2023 | 1,486,925 | 16,162 | $4.70 | |||||||||||||||||||
| October 2023 - December 2023 | 1,413,628 | 15,366 | 4.90 | ||||||||||||||||||||
| January 2024 - March 2024 | 4,104,919 | 45,109 | 3.77 | ||||||||||||||||||||
| April 2024 - June 2024 | 446,321 | 4,905 | 3.93 | ||||||||||||||||||||
| July 2024 - September 2024 | 429,388 | 4,667 | 4.01 | ||||||||||||||||||||
| October 2024 - December 2024 | 413,899 | 4,499 | 4.32 | ||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Differential ($/MMBtu)(2) | ||||||||||||||||||||
Natural gas basis differential swaps | July 2023 - September 2023 | 6,210,000 | 67,500 | $(1.30) | |||||||||||||||||||
| October 2023 - December 2023 | 6,210,000 | 67,500 | (1.30) | ||||||||||||||||||||
| January 2024 - March 2024 | 3,640,000 | 40,000 | (0.52) | ||||||||||||||||||||
| April 2024 - June 2024 | 1,820,000 | 20,000 | (0.67) | ||||||||||||||||||||
| July 2024 - September 2024 | 1,840,000 | 20,000 | (0.66) | ||||||||||||||||||||
| October 2024 - December 2024 | 1,840,000 | 20,000 | (0.64) | ||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Differential ($/MMBtu)(3) | ||||||||||||||||||||
Natural gas basis differential swaps | July 2023 - September 2023 | 1,840,000 | 20,000 | $(0.30) | |||||||||||||||||||
| October 2023 - December 2023 | 1,840,000 | 20,000 | (0.30) | ||||||||||||||||||||
| January 2024 - March 2024 | 2,730,000 | 30,000 | (0.02) | ||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Collar Price Ranges ($/MMBtu)(4) | ||||||||||||||||||||||||||
Natural gas collars | July 2023 - September 2023 | 6,563,075 | 71,338 | $3.64 | - | $7.52 | |||||||||||||||||||||||
| October 2023 - December 2023 | 6,636,372 | 72,134 | 3.66 | - | 8.22 | ||||||||||||||||||||||||
| January 2024 - March 2024 | 3,175,081 | 34,891 | 3.36 | - | 9.44 | ||||||||||||||||||||||||
| April 2024 - June 2024 | 1,373,679 | 15,095 | 3.00 | - | 6.45 | ||||||||||||||||||||||||
| July 2024 - September 2024 | 1,410,612 | 15,333 | 3.00 | - | 6.52 | ||||||||||||||||||||||||
| October 2024 - December 2024 | 1,426,101 | 15,501 | 3.25 | - | 7.30 | ||||||||||||||||||||||||
(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.
25
PERMIAN RESOURCES CORPORATION
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, all gains and losses are recognized in the Company’s consolidated statements of operations. All derivative instruments are recorded at fair value in the consolidated balance sheets, other than derivative instruments that meet the “normal purchase normal sale” exclusion, and any fair value gains and losses are recognized in current period earnings.
The following table presents the impact of the Company’s derivative instruments in its consolidated statements of operations for the periods presented:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
(in thousands) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
Net gain (loss) on derivative instruments | $ | 20,601 | $ | (34,134) | $ | 75,113 | $ | (163,657) | |||||||||||||||
Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives are included in the accompanying consolidated balance sheets as derivative assets and liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master netting agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The tables below summarize the fair value amounts and the classification in the consolidated balance sheets of the Company’s derivative contracts outstanding at the respective balance dates, as well as the gross recognized derivative assets, liabilities and offset amounts:
| Balance Sheet Classification | Gross Fair Value Asset/Liability Amounts | Gross Amounts Offset(1) | Net Recognized Fair Value Assets/Liabilities | ||||||||||||||||||||
(in thousands) | June 30, 2023 | ||||||||||||||||||||||
Derivative Assets | |||||||||||||||||||||||
Commodity contracts | Derivative instruments | $ | 103,121 | $ | (15,384) | $ | 87,737 | ||||||||||||||||
| Other noncurrent assets | 26,082 | (2,805) | 23,277 | ||||||||||||||||||||
Derivative Liabilities | |||||||||||||||||||||||
Commodity contracts | Derivative instruments | $ | 15,738 | $ | (15,384) | $ | 354 | ||||||||||||||||
| Other noncurrent liabilities | 2,900 | (2,805) | 95 | ||||||||||||||||||||
| December 31, 2022 | |||||||||||||||||||||||
Derivative Assets | |||||||||||||||||||||||
Commodity contracts | Derivative instruments | $ | 125,120 | $ | (24,323) | $ | 100,797 | ||||||||||||||||
| Other noncurrent assets | 22,016 | (3,691) | 18,325 | ||||||||||||||||||||
Derivative Liabilities | |||||||||||||||||||||||
Commodity contracts | Derivative instruments | $ | 26,321 | $ | (24,323) | $ | 1,998 | ||||||||||||||||
| Other noncurrent liabilities | 6,349 | (3,691) | 2,658 | ||||||||||||||||||||
(1) The Company has agreements in place with each of its counterparties that allow for the financial right of offset for derivative assets against derivative liabilities at settlement or in the event of a default under the agreements or if contracts are terminated.
Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are primarily lenders under OpCo’s Credit Agreement. The Company enters into new hedge arrangements only with participants under its Credit Agreement, since these institutions are secured equally with the holders of any OpCo bank debt, which eliminates the potential need to post collateral when the 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 lender under OpCo’s Credit Agreement as referenced above.
26
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 8—Fair Value Measurements
Recurring Fair Value Measurements
The Company follows ASC Topic 820, Fair Value Measurement and Disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
•Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
•Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
•Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.
The following table presents, for each applicable level within the fair value hierarchy, the Company’s net derivative assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis:
(in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||
| 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 judgment and considers factors specific to the asset or liability. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. There were no transfers between any of the fair value levels during any period presented.
Derivatives
The Company uses Level 2 inputs to measure the fair value of its oil and natural gas commodity derivatives. The Company uses industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
Nonrecurring Fair Value Measurements
The Company applies the provisions of the fair value measurement standard on a nonrecurring basis to its non-financial assets and liabilities, including proved oil and gas properties. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances.
Oil and Gas Property Acquisitions. The fair value measurements of assets acquired and liabilities assumed are measured 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 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 judgements and estimates by the Company’s management at the time of valuation.
27
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Impairment of Oil and Natural Gas Properties. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that the fair value of these assets may be below their carrying value. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows from oil and gas properties is less than the carrying amount of the assets. In this circumstance, the Company then recognizes impairment expense for the amount by which the carrying amount of proved properties exceeds their estimated fair value. The Company reviews its oil and natural gas properties on a field-by-field basis.
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 calculation of ARO include the estimated future costs to plug and abandon oil and gas properties and reserve lives. Refer to Note 5—Asset Retirement Obligations for additional information on the Company’s ARO.
Other Financial Instruments
The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate their fair values because of the short-term maturities and/or liquid nature of these assets and liabilities.
The Company’s senior notes and borrowings under its Credit Agreement are accounted for at cost. The following table summarizes the carrying values, principal amounts and fair values of these instruments as of the dates indicated:
| June 30, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||
| Carrying Value | Principal Amount | Fair Value | Carrying Value | Principal Amount | Fair 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 OpCo’s Credit Agreement approximate fair value because its variable interest rates are tied to current market rates and the applicable credit spreads represent current market rates for the credit risk profile of the Company.
(2) The carrying values include associated unamortized debt issuance costs and any debt discounts as reflected in the consolidated balance sheets. The fair values are determined using quoted market prices for these debt securities, a Level 1 classification in the fair value hierarchy, and are based on the aggregate principal amount of the senior notes outstanding.
Note 9—Shareholders’ Equity and Noncontrolling Interest
Stock 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. A tax benefit of $2.5 million was recorded in equity as a result of the conversion of shares from the noncontrolling interest owner. No cash proceeds were received by the Company in connection with the conversions.
Dividends
During the six months ended June 30, 2023, the Company 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 (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 dividend of $0.05 per share of Class A Common Stock and a quarterly variable cash
28
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 31, 2024. The Repurchase Program can be used by the Company to reduce 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 the Company’s discretion and will be subject to market conditions, applicable legal requirements, available liquidity, compliance with the Company’s debt and other agreements and other factors. The Repurchase Program does not require any specific number of shares to be acquired and can be modified or discontinued by the Company’s Board of Directors at any time.
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 underlying shares of Class C Common Stock simultaneously being canceled.
Noncontrolling Interest
The noncontrolling interest relates to Common Units that were issued in connection 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 affected by various 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) for Class A Common Stock and the Class C Common Stock repurchase by the Company discussed above.
The Company consolidates the financial position, results of operations and cash flows of OpCo and reflects the portion retained by other holders of Common Units as a noncontrolling interest. Refer to the consolidated statements of shareholders’ equity for a summary of the activity attributable to the noncontrolling interest during the period.
Note 10—Earnings Per Share
Basic earnings per share (“EPS”) is calculated by dividing net income attributable to Class A Common stock by the weighted average shares of Class A Common Stock outstanding during each period. Diluted EPS is calculated by dividing adjusted net income by the weighted average shares of diluted Class 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, withholding amounts from the employee stock purchase plan (prior to its discontinuation in January 2023), all using the treasury stock method; (ii) equity-based restricted stock and performance stock units that were vested but not outstanding, using the treasury stock method; and (iii) the Company’s Class C Common Stock and potential shares issuable under our Convertible Senior Notes, both using the “if-converted” method, which is net of tax.
29
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table reflects the EPS computations for the periods indicated based on a weighted average number of Class A Common Stock outstanding each period:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (in thousands, except per share data) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| 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 tax | 1,376 | 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 outstanding | 315,168 | 284,992 | 305,593 | 284,922 | |||||||||||||||||||
| Add: Dilutive effects of Convertible Senior Notes | 27,605 | 27,074 | 27,460 | 27,074 | |||||||||||||||||||
| Add: Dilutive effects of equity awards and ESPP shares | 9,142 | 8,038 | 10,882 | 7,897 | |||||||||||||||||||
| Diluted weighted average shares of Class A Common Stock outstanding | 351,915 | 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 | |||||||||||||||
The following table presents shares excluded from the diluted earnings per share calculation for the periods presented as their impact was anti-dilutive:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (in thousands) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Out-of-the-money stock options | 1,416 | 2,049 | 1,665 | 2,073 | |||||||||||||||||||
| Weighted average shares of Class C Common Stock | 245,586 | — | 254,429 | — | |||||||||||||||||||
| Restricted stock | 208 | — | 104 | — | |||||||||||||||||||
| Performance stock units | 116 | — | 58 | 224 | |||||||||||||||||||
30
PERMIAN RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 11—Transactions with Related Parties
Riverstone Investment Group LLC (“Riverstone”), NGP Energy Capital (“NGP”), and Pearl Energy Investments (“Pearl”) and related affiliates of each entity each beneficially owned more than 10% equity interest in the Company as of June 30, 2023. Certain members of OpCo’s management owned profit interests at CEP III Holdings, LLC and its 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 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 Riverstone until the sale 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 third quarter of 2022.
(ii) A vendor arrangement with Streamline Innovations Inc, (“Streamline”) who was an affiliate of 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) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Lucid | |||||||||||||||||||||||
| Oil and gas sales | $ | — | $ | 9,107 | $ | — | $ | 18,590 | |||||||||||||||
| Gathering, processing and transportation expenses | — | 2,150 | — | 4,669 | |||||||||||||||||||
| Streamline | |||||||||||||||||||||||
| Lease operating expenses | 1,238 | — | 1,834 | — | |||||||||||||||||||
| (in thousands) | June 30, 2023 | December 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 12—Commitments and Contingencies
Commitments
The Company routinely enters into, extends or amends operating agreements in the ordinary course of business. Other than the 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 six months ended June 30, 2023. Please refer to Note 14—Commitments and Contingencies included in Part II, Item 8 in the Company’s 2022 Annual Report.
31
PERMIAN RESOURCES CORPORATION
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.
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 a contingent liability to be recognized as of the date of these consolidated financial statements.
Note 13—Revenues
Revenue from Contracts with Customers
Crude oil, natural gas and NGL sales are recognized at the point that control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials. As a result, the Company’s realized prices of oil, natural gas, and NGLs fluctuate to remain competitive with other available oil, natural gas, and NGLs supplies both globally (in the case of crude oil) and locally.
Oil and gas revenues presented within the consolidated statements of operations relate to the sale of oil, natural gas and NGLs as shown below:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 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.
32
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
On August 2, 2023, the Company announced 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 Company’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 shareholders of record as of August 15, 2023.
33
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements and related notes. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, future market prices for oil, natural gas and NGLs, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, the implementation and actual result of the Merger (defined below) and other uncertainties, as well as those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements” and under the heading “Item 1A. Risk Factors” in this Quarterly Report and our 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
Permian Resources Corporation is an independent oil and natural gas company focused on the responsible acquisition, optimization and development of high-return oil and natural gas properties. Our assets are located in the core of the Delaware Basin. Our principal business objective is to increase shareholder value by efficiently developing our oil and natural gas assets in an environmentally and socially responsible way, with an overall objective of improving our rates of return and generating sustainable free cash flow. Unless otherwise specified or the context otherwise requires, all references in these discussions to “Permian Resources,” “we,” “us,” or “our” are to 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 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 it is likely that commodity prices, as well as commodity price differentials, will continue to be volatile due to fluctuations in global supply and demand, inventory levels, geopolitical events, federal and state government regulations, weather conditions, the global transition to alternative energy sources, supply chain constraints and other factors. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2021:
| 2021 | 2022 | 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | Q1 | Q2 | Q3 | Q4 | Q1 | Q2 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| 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 and lower futures curves for oil and gas prices can result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, future business and operations, and/or our ability to finance planned capital
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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 realized prices may also reduce the borrowing base under 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.
Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, 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 increases to the costs of our oilfield goods, services and personnel, which can in turn cause our capital expenditures and operating costs to rise.
2023 Highlights and Future Considerations
2023 Acquisition
On February 16, 2023, we completed an 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 our existing 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 the 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 Reeves County, Texas. The proceeds from the divestiture were used to fund the bolt-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 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.
During the 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 underlying shares of Class C Common Stock simultaneously being canceled.
Financing
On April 24, 2023, we entered into the third amendment (the “Third Amendment”) to the Third Amended and Restated Credit Agreement. 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.
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Results of Operations
Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 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:
| Three Months Ended June 30, | Increase/(Decrease) | ||||||||||||||||||||||
| 2023 | 2022 | $ | % | ||||||||||||||||||||
| 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) 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. Total net revenues for the three months ended June 30, 2023 were $150.7 million (or 32%) higher than total net revenues for the three months ended June 30, 2022. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Net production volumes for oil, natural gas and NGLs increased 130%, 129% and 163%, respectively, between periods. The increase in oil production resulted from placing 140 wells online since the second quarter of 2022 as compared to 50 wells brought online since the second quarter of 2021. Oil production also benefited from wells acquired in the Merger with Colgate, which added 1,663 MBbls of net oil production to the three months ended June 30, 2023. These oil volume increases were partially offset by normal production decline across our existing wells. Natural gas and NGLs are produced concurrently with our crude oil volumes, which typically results in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold, driving the 129% and 163% respective increases in gas and NGL volumes between periods.
These increases were partially offset by decreases in the average realized sales prices for oil, natural gas and NGLs, which decreased 32%, 80% and 54%, respectively, in the second quarter of 2023 compared to the same 2022 period. The 32% decrease in the average realized oil price was mainly the result of 32% lower NYMEX crude prices between periods. The average realized sales price of natural gas decreased 80% mainly due to 71% lower average NYMEX gas prices between periods as well as a larger proportional gas differential in the second quarter of 2023 compared to the same 2022 period. The 54% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products in the second quarter of 2023 as compared to the second quarter 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 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) | ||||||||||||||||||||||
| 2023 | 2022 | Change | % | ||||||||||||||||||||
| Operating costs (in thousands): | |||||||||||||||||||||||
| Lease operating expenses | $ | 82,991 | $ | 28,900 | $ | 54,091 | 187 | % | |||||||||||||||
| Severance and ad valorem taxes | 48,927 | 34,695 | 14,232 | 41 | % | ||||||||||||||||||
| Gathering, processing and transportation expenses | 21,753 | 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) | % | |||||||||||||||
Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended June 30, 2023 increased $54.1 million compared to the three months ended June 30, 2022. Higher LOE for the second quarter of 2023 was primarily related to (i) additional costs associated with the 309 gross operated horizontal wells acquired in the Merger on September 1, 2022; (ii) higher fixed and semi-variable well costs, such as water disposal, monthly equipment rentals, repair work, wellhead chemical costs, labor, and electricity that all stemmed from the new wells drilled and the associated production increase between periods; and (iii) higher regulatory and preventative costs between periods.
LOE per Boe was $5.50 for the second quarter of 2023, which represents an increase of $0.98 per Boe (or 22%) from the second quarter of 2022. This increase 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 partially offset by lower per BOE workover costs 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 based on the market value of our oil and gas production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of proved developed oil and gas properties and vary across the different counties in which we operate. Severance taxes for the second quarter of 2023 increased $7.7 million compared to the same 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 total net revenues increased to 7.8% for the three months ended June 30, 2023 as compared to 7.3% for the same prior year quarter. This increase in rate was 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 June 30, 2023 as compared to the three months ended June 30, 2022. This decrease in net revenues resulted in severance and ad valorem taxes as a percentage of total net revenues to increase period over period. Refer to Note 13—Revenues for additional information on our natural gas gathering and processing contracts.
Gathering, Processing and Transportation 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 costs being recognized as a reduction to our gas and NGL revenues in the first quarter 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 two of our existing gas 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 depreciation, depletion and amortization (“DD&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 | |||||||
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 developed and proved undeveloped reserves. Our DD&A rate increased $1.44 per Boe between periods due to (i) facility, infrastructure and artificial lift costs incurred during the second quarter of 2023, which have minimal associated proved reserve adds; and (ii) downward revisions to proved and proved developed reserves, primarily natural gas reserves, during the second quarter of 2023 related to lower SEC reserve pricing and 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) | 2023 | 2022 | |||||||||
| Cash general and administrative expenses | $ | 17,694 | $ | 12,434 | |||||||
| Stock-based compensation - equity awards | 35,042 | 6,106 | |||||||||
| Stock-based compensation - liability awards | — | (8,593) | |||||||||
| General and administrative expenses | $ | 52,736 | $ | 9,947 | |||||||
G&A expenses for the three months ended June 30, 2023 were $52.7 million compared to $9.9 million for the 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 due to (i) an increase of $28.9 million in equity awards compensation period over period for the acceleration of certain awards in the second quarter of 2023 as a result of officer and employee exits stemming from the Merger; and (ii) an increase of $8.6 million period over period related to liability awards, as we no longer had any liability-based equity awards outstanding during the second quarter of 2023. 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 second quarter of 2023 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 three months ended June 30, 2022. This decrease period over period relates to a $3.9 million decrease in consultancy, legal and advisory fees, partially offset by a $2.6 million increase in severance 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 associated with individually insignificant unproved properties.
Exploration and Other Expenses. The following table summarizes our exploration and other expenses for the periods indicated:
| Three Months Ended June 30, | |||||||||||
| (in thousands) | 2023 | 2022 | |||||||||
| Geological and geophysical costs | $ | 3,751 | $ | 1,534 | |||||||
| Stock-based compensation - equity awards | 652 | 551 | |||||||||
| Other expenses | 860 | (131) | |||||||||
| Exploration and other expenses | $ | 5,263 | $ | 1,954 | |||||||
Exploration and other expenses were $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 topographical studies, geographical and geophysical (“G&G”) projects, salaries and expenses of G&G personnel and includes other operating costs. The period over period increase was related to (i) increased costs incurred on 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 second quarter of 2023 associated with increased headcount.
Other Income and Expenses.
Interest Expense. The following table summarizes our interest expense for the periods indicated:
| Three Months Ended June 30, | |||||||||||
(in thousands) | 2023 | 2022 | |||||||||
| Credit facility | $ | 7,667 | $ | 772 | |||||||
| 5.375% Senior Notes due 2026 | 3,889 | 3,889 | |||||||||
| 7.75% Senior Notes due 2026 | 5,813 | — | |||||||||
| 6.875% Senior Notes due 2027 | 6,125 | 6,125 | |||||||||
| 3.25% Convertible Senior Notes due 2028 | 1,381 | 1,381 | |||||||||
| 5.875% Senior Notes due 2029 | 10,281 | — | |||||||||
| Amortization of debt issuance costs and debt discount | 3,482 | 2,734 | |||||||||
| Interest capitalized | (2,117) | (575) | |||||||||
| Financing lease interest obligation | 305 | — | |||||||||
| Total | $ | 36,826 | $ | 14,326 | |||||||
Interest expense increased $22.5 million for the three months ended June 30, 2023 as compared to the three months ended June 30, 2022 primarily due to (i) $16.1 million in additional interest costs on the senior notes we assumed in the Merger; and (ii) $6.9 million in higher interest incurred on our Credit Agreement due to additional borrowings outstanding and higher interest rates during the 2023 period.
Our weighted average borrowings outstanding under our Credit Agreement were $370.2 million and $5.4 million for the three months ended June 30, 2023 and 2022, respectively. Our Credit Agreement’s weighted average effective interest rate increased to 7.1% from 2.7% for the 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) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding; and (ii) monthly cash settlements on any closed out hedge positions during the period.
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The following table presents gains and losses on our derivative instruments for the periods indicated:
| Three Months Ended June 30, | |||||||||||
(in thousands) | 2023 | 2022 | |||||||||
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) Benefit. The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated:
| Three Months Ended June 30, | |||||||||||
(in thousands) | 2023 | 2022 | |||||||||
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 June 30, 2023 and 2022 differs from the amounts that would be provided by applying the U.S. federal statutory rate of 21% to pre-tax book income (loss) primarily due to (i) 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 taxes; and (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.
For the three months ended June 30, 2022, we generated pre-tax net income of $233.3 million and recorded income tax expense of $41.5 million. The primary factor decreasing our income tax expense below the U.S. statutory rate was the partial release of our deferred tax valuation allowance in the second quarter of 2022.
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Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 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:
| Six Months Ended June 30, | Increase/(Decrease) | ||||||||||||||||||||||
| 2023 | 2022 | $ | % | ||||||||||||||||||||
| 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) 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. Total net revenues for the six months ended June 30, 2023 were $419.7 million, or 51%, higher than total net revenues for the six months ended June 30, 2022. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Net production volumes for oil, natural gas, and NGLs increased 134%, 135%, and 180%, respectively, between periods. The oil production volume increase resulted from placing 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 current period also benefited from wells acquired in the Merger with Colgate, which added 3,475 MBbls of net oil production to the six months ended June 30, 2023. These oil volume increases were partially offset by normal production declines across our existing wells. Natural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in oil quantities sold and natural gas and NGL quantities sold driving the 135% and 180%, respective, increase in gas and NGL volumes between periods.
These increases were partially offset by decreases in the average realized sales prices for oil, natural gas and NGLs, which decreased 25%, 70%, and 49%, respectively, in the first half of 2023 compared to the same 2022 period. The 25% decrease in the average realized oil price was mainly the result of 26% lower NYMEX crude prices between periods, slightly offset by improved oil differentials. The average realized sales price of natural gas decreased 70% due to 60% lower average NYMEX gas prices between periods as well as a larger proportional gas differential in the first half of 2023 compared to the same 2022 period. The 49% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products for the first half of 2023 as compared to the first half 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 market conditions section above.
Operating Expenses. The following table summarizes our operating expenses for the periods indicated:
| Six Months Ended June 30, | Increase/(Decrease) | ||||||||||||||||||||||
| 2023 | 2022 | Change | % | ||||||||||||||||||||
| Operating costs (in thousands): | |||||||||||||||||||||||
| Lease operating expenses | $ | 157,523 | $ | 57,634 | $ | 99,889 | 173 | % | |||||||||||||||
| Severance and ad valorem taxes | 97,436 | 59,746 | 37,690 | 63 | % | ||||||||||||||||||
| Gathering, processing and transportation expenses | 37,235 | 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) | % | |||||||||||||||
Lease Operating Expenses. LOE for the six months ended June 30, 2023 increased $99.9 million compared to the six months ended June 30, 2022. Higher LOE for the first half of 2023 was primarily related to (i) additional costs associated with the 309 gross operated horizontal wells acquired in the Merger on September 1, 2022; (ii) higher fixed and semi-variable well costs, such as water disposal, monthly equipment rentals, repair work, wellhead chemical costs, labor, and electricity that all stemmed from new wells drilled and the associated production increase between periods; and (iii) higher regulatory and preventative costs between periods.
LOE per Boe was $5.44 for the six months ended June 30, 2023, which represents an increase of $0.60 per Boe (or 12%) from the six months ended June 30, 2022. This increase was primarily driven by per Boe 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 based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Severance taxes for the first half of 2023 increased $25.7 million compared to the same 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 total net revenues increased to 7.9% for the first half of 2023 as compared to 7.3% for the same 2022 period. This increase in rate was 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 first half of 2023 compared to the first half of 2022. This decrease in net revenues resulted in severance and ad valorem taxes as a percentage of total net revenues to increase period over period. Refer to Note 13—Revenues for additional information on 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) | 2023 | 2022 | |||||||||
| Depreciation, depletion and amortization | $ | 403,945 | $ | 153,126 | |||||||
| Depreciation, depletion and amortization per Boe | $ | 13.96 | $ | 12.85 | |||||||
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 developed and proved undeveloped reserves. Our DD&A rate increased $1.11 per Boe between periods due to (i) facility, infrastructure and artificial lift costs incurred during the first half of 2023, which have minimal associated proved reserve adds; and (ii) downward revisions to proved and proved developed reserves, primarily natural gas reserves, during the first half of 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 awards | 51,749 | 11,220 | |||||||||
| Stock-based compensation expense - liability awards | — | 5,127 | |||||||||
| General and administrative expenses | $ | 88,210 | $ | 40,550 | |||||||
G&A expenses for the six months ended June 30, 2023 were $88.2 million compared to $40.6 million for the 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 largely due to an 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 severance and related benefits associated with employee terminations in connection with the Merger, which was partially offset by a $1.8 million decrease 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 six months ended June 30, 2022. 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 awards | 1,816 | 982 | |||||||||
| Other expenses | 1,749 | 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 seismic studies of $1.5 million; (ii) $1.4 million in higher G&G personnel costs in the first half of 2023 associated with increased headcount; (iii) $0.9 million in costs incurred in 2023 associated with a nonrecurring legal settlement; and (iv) $0.8 million in higher stock-based compensation related to accelerated vesting of employees terminated in connection with the Merger.
Other Income and Expenses.
Interest Expense. The following table summarizes our interest expense for the periods indicated:
| Six Months Ended June 30, | |||||||||||
(in thousands) | 2023 | 2022 | |||||||||
| Credit facility | $ | 16,159 | $ | 1,649 | |||||||
| 5.375% Senior Notes due 2026 | 7,778 | 7,778 | |||||||||
| 7.75% Senior Notes due 2026 | 11,626 | — | |||||||||
| 6.875% Senior Notes due 2027 | 12,250 | 12,250 | |||||||||
| 3.25% Convertible Senior Notes due 2028 | 2,762 | 2,762 | |||||||||
| 5.875% Senior Notes due 2029 | 20,562 | — | |||||||||
| Amortization of debt issuance costs and debt discount | 6,278 | 4,226 | |||||||||
| Interest capitalized | (4,117) | (1,185) | |||||||||
| Financing lease interest obligation | 305 | — | |||||||||
| Total | $ | 73,603 | $ | 27,480 | |||||||
Interest expense was $46.1 million higher for the six months ended June 30, 2023 compared to the same 2022 period mainly due to (i) $32.2 million in additional interest costs on the senior notes we assumed in the 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 borrowings outstanding under our Credit Agreement were $412.7 million versus $16.5 million for the first half of 2023 and 2022, respectively. Our Credit Agreement’s weighted average effective interest rate was 6.9% and 2.9% for the six months ended June 30, 2023 and 2022, respectively.
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Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding and (ii) monthly cash settlements on any closed out hedge positions during the period.
The following table presents gains and losses on our derivative instruments for the periods indicated:
| Six Months Ended June 30, | |||||||||||
(in thousands) | 2023 | 2022 | |||||||||
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. The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated:
| Six Months Ended June 30, | |||||||||||
(in thousands) | 2023 | 2022 | |||||||||
Income (loss) before income taxes | $ | 429,557 | $ | 255,891 | |||||||
Income tax (expense) benefit | (60,802) | (48,263) | |||||||||
Our provisions for income taxes for the first half of 2023 and 2022 differs from the amounts that would be provided by applying the U.S. federal statutory rate of 21% to pre-tax book income (loss) primarily due to (i) 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 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 during the first half of 2022.
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Liquidity and Capital Resources
Overview
Our drilling and completion activities require us to make significant capital expenditures. Historically, our primary sources of liquidity have been cash flows from operations, borrowings under our revolving credit facility, proceeds from offerings of debt or equity securities, or proceeds from the sale of oil and gas properties. Our future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary use of capital has been for drilling and development capital expenditures and the acquisition of oil and natural gas properties.
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 total capital expenditures 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 2023 to be between $1.25 billion to $1.45 billion. We funded our capital expenditures for the six months ended June 30, 2023 entirely from cash flows from operations, and 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 cash dividends and distributions paid totaled $85.5 million for the six months ended June 30, 2023. Additionally, as a part of our shareholder return program, we repurchased 2.8 million shares of Class C Common Stock for $29.4 million under our stock repurchase program during the six months ended June 30, 2023.
The stock repurchase program can be used to reduce our shares of Common Stock outstanding. Such repurchases would be made at terms and prices determined by us based upon prevailing market conditions, applicable legal requirements, available liquidity, compliance with our debt and other agreements and other factors. 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 our capital expenditures. We can choose to defer or accelerate a portion of our planned capital expenditures depending on a variety of factors, including but not limited to: prevailing and anticipated prices for oil and natural gas; oil storage or transportation constraints; the success of our drilling activities; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; seasonal conditions; property or land acquisition costs; and the level of participation by other working interest owners.
We cannot ensure that cash flows from operations or other sources of needed capital will be available at acceptable terms or at all. Further, our ability to access the public or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control.
Analysis of Cash Flow Changes
The following table summarizes our cash flows for the periods indicated:
| Six Months Ended June 30, | |||||||||||
| (in thousands) | 2023 | 2022 | |||||||||
| 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) | |||||||||
For the six months ended June 30, 2023, we generated $886.7 million of cash from operating activities, an increase of $431.6 million from the same period in 2022. Cash provided by operating activities increased primarily due to higher production volumes, lower GP&T expenses, higher cash settlements on derivatives and the timing of our receivable collections for the six months ended June 30, 2023 as compared to the same 2022 period. These increasing factors were partially offset by lower realized prices for all commodities, higher lease operating expenses, severance and ad valorem taxes, merger and integration expense, and cash G&A expenses as well as the timing of our supplier payments for the six months ended June 30, 2023 as
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compared to the same 2022 period. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs between periods.
During the six months ended June 30, 2023, cash flows from operating activities, cash on hand, and sales proceeds together with contingent consideration of $124.0 million from the sale of oil and natural gas properties were used to fund $686.6 million of drilling and development cash expenditures, repay net borrowings of $85 million under our Credit Agreement, fund acquisitions of oil and gas 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.
During 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 Agreement.
Credit Agreement
OpCo, our 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 that as of June 30, 2023, had a borrowing base of $2.5 billion and elected commitments of $1.5 billion. As of June 30, 2023, we had $300 million of borrowings outstanding and $1.2 billion in available borrowing capacity, net of $5.8 million in letters of credit outstanding.
On April 24, 2023, we entered into the Third Amendment to the Credit Agreement. 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 Credit Agreement contains restrictive covenants that limit our ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or redeem junior debt; (vi) enter into commodity hedges exceeding a specified percentage of our expected production; (vii) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates.
The Credit Agreement also requires OpCo to maintain compliance with the following financial ratios:
(i) a current ratio, which is the ratio of OpCo’s consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and
(ii) a leverage ratio, as defined within the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX (as defined within the Credit Agreement) for the most recent quarter annualized, of not greater than 3.5 to 1.0.
The 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 and through the filing of this 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.
Convertible Senior Notes
On 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 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 to the critical accounting policies as disclosed in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates in our 2022 Annual Report.
New Accounting Pronouncements
There were no significant new accounting 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
The term “market risk” as it applies to our business refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates, and we are exposed to market risk as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our primary market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue for the foreseeable future. Based on our production for the first 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 oil prices per Bbl, $5.6 million for each 10% change in natural gas prices per Mcf, and $11.0 million for each 10% change in NGL prices per Bbl.
Due to this volatility, we have historically used, and we may elect to continue to selectively use, commodity derivative instruments (such as collars, swaps and basis swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flows that can emanate from fluctuations in oil and natural gas prices, and thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, but alternatively they partially limit our potential gains from future increases in prices. Our Credit Agreement limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated projected production from proved properties.
The table below summarizes the terms of the derivative contracts we had in place as of June 30, 2023 and additional contracts entered into through July 31, 2023. Refer to Note 7—Derivative Instruments in Part I, Item 1 of this Quarterly Report for open derivative positions as of June 30, 2023.
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Crude Price ($/Bbl)(1) | ||||||||||||||||||||
Crude oil swaps | July 2023 - September 2023 | 1,748,000 | 19,000 | $85.04 | |||||||||||||||||||
| October 2023 - December 2023 | 1,748,000 | 19,000 | 82.93 | ||||||||||||||||||||
| January 2024 - March 2024 | 1,547,000 | 17,000 | 77.14 | ||||||||||||||||||||
| April 2024 - June 2024 | 1,547,000 | 17,000 | 75.99 | ||||||||||||||||||||
| July 2024 - September 2024 | 1,564,000 | 17,000 | 74.89 | ||||||||||||||||||||
| October 2024 - December 2024 | 1,564,000 | 17,000 | 73.94 | ||||||||||||||||||||
| January 2025 - March 2025 | 450,000 | 5,000 | 69.56 | ||||||||||||||||||||
| April 2025 - June 2025 | 455,000 | 5,000 | 68.49 | ||||||||||||||||||||
| July 2025 - September 2025 | 460,000 | 5,000 | 67.46 | ||||||||||||||||||||
| October 2025 - December 2025 | 460,000 | 5,000 | 66.54 | ||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Collar Price Ranges ($/Bbl)(2) | ||||||||||||||||||||||||||
| Crude oil collars | July 2023 - September 2023 | 644,000 | 7,000 | $76.43 | - | $92.70 | |||||||||||||||||||||||
| October 2023 - December 2023 | 644,000 | 7,000 | 76.43 | - | 92.70 | ||||||||||||||||||||||||
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| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(3) | ||||||||||||||||||||
| Crude oil basis differential swaps | July 2023 - September 2023 | 1,025,000 | 11,141 | $0.63 | |||||||||||||||||||
| October 2023 - December 2023 | 1,025,002 | 11,141 | 0.63 | ||||||||||||||||||||
| January 2024 - March 2024 | 1,092,000 | 12,000 | 0.66 | ||||||||||||||||||||
| April 2024 - June 2024 | 1,092,000 | 12,000 | 0.66 | ||||||||||||||||||||
| July 2024 - September 2024 | 1,104,000 | 12,000 | 0.66 | ||||||||||||||||||||
| October 2024 - December 2024 | 1,104,000 | 12,000 | 0.66 | ||||||||||||||||||||
| January 2025 - March 2025 | 450,000 | 5,000 | 0.95 | ||||||||||||||||||||
| April 2025 - June 2025 | 455,000 | 5,000 | 0.95 | ||||||||||||||||||||
| July 2025 - September 2025 | 460,000 | 5,000 | 0.95 | ||||||||||||||||||||
| October 2025 - December 2025 | 460,000 | 5,000 | 0.95 | ||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(4) | ||||||||||||||||||||
| Crude oil roll differential swaps | July 2023 - September 2023 | 1,656,000 | 18,000 | $1.16 | |||||||||||||||||||
| October 2023 - December 2023 | 1,656,000 | 18,000 | 1.16 | ||||||||||||||||||||
| January 2024 - March 2024 | 1,092,000 | 12,000 | 0.68 | ||||||||||||||||||||
| April 2024 - June 2024 | 1,092,000 | 12,000 | 0.67 | ||||||||||||||||||||
| July 2024 - September 2024 | 1,104,000 | 12,000 | 0.66 | ||||||||||||||||||||
| October 2024 - December 2024 | 1,104,000 | 12,000 | 0.66 | ||||||||||||||||||||
| January 2025 - March 2025 | 180,000 | 2,000 | 0.37 | ||||||||||||||||||||
| April 2025 - June 2025 | 182,000 | 2,000 | 0.37 | ||||||||||||||||||||
| July 2025 - September 2025 | 184,000 | 2,000 | 0.37 | ||||||||||||||||||||
| October 2025 - December 2025 | 184,000 | 2,000 | 0.37 | ||||||||||||||||||||
(1) These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices during each applicable monthly settlement period.
(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.
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| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Gas Price ($/MMBtu)(1) | ||||||||||||||||||||
Natural gas swaps | July 2023 - September 2023 | 1,486,925 | 16,162 | $4.70 | |||||||||||||||||||
| October 2023 - December 2023 | 1,413,628 | 15,366 | 4.90 | ||||||||||||||||||||
| January 2024 - March 2024 | 4,104,919 | 45,109 | 3.77 | ||||||||||||||||||||
| April 2024 - June 2024 | 446,321 | 4,905 | 3.93 | ||||||||||||||||||||
| July 2024 - September 2024 | 429,388 | 4,667 | 4.01 | ||||||||||||||||||||
| October 2024 - December 2024 | 413,899 | 4,499 | 4.32 | ||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Differential ($/MMBtu)(2) | ||||||||||||||||||||
Natural gas basis differential swaps | July 2023 - September 2023 | 6,210,000 | 67,500 | $(1.30) | |||||||||||||||||||
| October 2023 - December 2023 | 6,210,000 | 67,500 | (1.30) | ||||||||||||||||||||
| January 2024 - March 2024 | 3,640,000 | 40,000 | (0.52) | ||||||||||||||||||||
| April 2024 - June 2024 | 1,820,000 | 20,000 | (0.67) | ||||||||||||||||||||
| July 2024 - September 2024 | 1,840,000 | 20,000 | (0.66) | ||||||||||||||||||||
| October 2024 - December 2024 | 1,840,000 | 20,000 | (0.64) | ||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Differential ($/MMBtu)(3) | ||||||||||||||||||||
Natural gas basis differential swaps | July 2023 - September 2023 | 1,840,000 | 20,000 | $(0.30) | |||||||||||||||||||
| October 2023 - December 2023 | 1,840,000 | 20,000 | (0.30) | ||||||||||||||||||||
| January 2024 - March 2024 | 3,640,000 | 40,000 | 0.00 | ||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Collar Price Ranges ($/MMBtu)(4) | ||||||||||||||||||||||||||
Natural gas collars | July 2023 - September 2023 | 6,563,075 | 71,338 | $3.64 | - | $7.52 | |||||||||||||||||||||||
| October 2023 - December 2023 | 6,636,372 | 72,134 | 3.66 | - | 8.22 | ||||||||||||||||||||||||
| January 2024 - March 2024 | 3,175,081 | 34,891 | 3.36 | - | 9.44 | ||||||||||||||||||||||||
| April 2024 - June 2024 | 1,373,679 | 15,095 | 3.00 | - | 6.45 | ||||||||||||||||||||||||
| July 2024 - September 2024 | 1,410,612 | 15,333 | 3.00 | - | 6.52 | ||||||||||||||||||||||||
| October 2024 - December 2024 | 1,426,101 | 15,501 | 3.25 | - | 7.30 | ||||||||||||||||||||||||
(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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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) At inception, new derivative contracts entered into by us have no intrinsic value.
A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of June 30, 2023 would cause a $86.7 million increase or $88.0 million decrease, respectively, in this fair value position, and a hypothetical upward or downward shift of 10% per MMBtu in the NYMEX forward curve for natural gas as of June 30, 2023 would cause a $4.7 million increase or $5.1 million decrease in this same fair value position.
Interest Rate Risk
Our ability to borrow and the rates offered by lenders can be adversely affected by deteriorations in the credit markets and/or downgrades in our credit rating. 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, 2023, we had $300.0 million of borrowings outstanding under our revolving credit facility, with a weighted average interest rate of 7.0%. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the weighted average interest rate would be approximately $3.0 million per year. We do not currently have or intend to enter into any derivative hedge contracts to protect against fluctuations in interest rates applicable to our outstanding indebtedness.
The remaining long-term debt balance of $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 management, including our principal executive officers 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 June 30, 2023. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officers 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 officers and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2023 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There were no changes in the system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) during the six months ended June 30, 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Refer to 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 exposed to environmental 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 costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of June 30, 2023 which have not been provided for or would otherwise have a material impact on our financial statements; 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 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
In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our 2022 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2022 Annual Report or our 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
Exhibit Number | Description of Exhibit | |||||||
| 10.1 | ||||||||
| 10.2# | ||||||||
| 31.1* | ||||||||
| 31.2* | ||||||||
| 31.3* | ||||||||
| 32.1* | ||||||||
| 32.2* | ||||||||
| 101.INS* | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | |||||||
| 101.SCH* | Inline XBRL Taxonomy Extension Schema Document. | |||||||
| 101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | |||||||
| 101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document. | |||||||
| 101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document. | |||||||
| 101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | |||||||
# Management contract or compensatory plan or agreement.
* Filed herewith.
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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 | ||||||||
| By: | /s/ GUY M. OLIPHINT | |||||||
Guy M. Oliphint Executive Vice President and Chief Financial Officer | ||||||||
| Date: | August 3, 2023 | |||||||
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