| | Page(s) |
| | |
| Report of Independent Auditors | 1–2 |
| Consolidated Financial Statements | |
Balance Sheets | 3 |
Statements of Operations | 4 |
Statements of Members’ Equity | 5 |
Statements of Cash Flows | 6 |
Notes to Financial Statements | 7–37 |
Report of Independent Auditors
To the Board of Managers of Maverick Natural Resources, LLC
Opinion
We have audited the accompanying consolidated financial statements of Maverick Natural Resources, LLC and its subsidiaries (the “Company”), which comprise the consolidated balance sheets as of December 31, 2023 and 2022, and the related consolidated statements of operations, members’ equity, and cash flows for the years then ended, including the related notes (collectively referred to as the “consolidated financial statements”).
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.
Basis for Opinion
We conducted our audit in accordance with auditing standards generally accepted in the United States of America (US GAAS). Our responsibilities under those standards are further described in the Auditors’ Responsibilities for the Audit of the Consolidated Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audit. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Responsibilities of Management for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the consolidated financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for one year after the date the consolidated financial statements are available to be issued.
Auditors’ Responsibilities for the Audit of the Consolidated Financial Statements
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditors’ report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with US GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the consolidated financial statements.
In performing an audit in accordance with US GAAS, we:
| ● | Exercise professional judgment and maintain professional skepticism throughout the audit. |
| ● | Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. |
| ● | Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, no such opinion is expressed. |
| ● | Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the consolidated financial statements. |
| ● | Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for a reasonable period of time. |
We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
April 29, 2024
| (in thousands of dollars) | | December 31, | |
| Assets | | 2023 | | | 2022 | |
| | | | | | |
Current assets | | | | | | |
| Cash | | $ | 53,263 | | | $ | 10 | |
| Restricted cash - current | | | 31,936 | | | | 3,232 | |
| Accounts receivable, net | | | 140,260 | | | | 197,228 | |
| Derivative instruments | | | 46,503 | | | | 1,051 | |
| Inventory | | | 2,209 | | | | 1,806 | |
| Prepaid expenses and other current assets | | | 7,089 | | | | 8,244 | |
| Total current assets | | | 281,260 | | | | 211,571 | |
Property, plant and equipment | | | | | | | | |
| Oil and natural gas properties | | | 2,674,820 | | | | 2,426,672 | |
| Other property, plant and equipment | | | 110,888 | | | | 77,230 | |
| Property, plant and equipment | | | 2,785,708 | | | | 2,503,902 | |
| Accumulated depletion, depreciation, and impairment | | | (1,097,788 | ) | | | (876,451 | ) |
| Property, plant and equipment, net | | | 1,687,920 | | | | 1,627,451 | |
Other long-term assets | | | | | | | | |
| Restricted cash | | | – | | | | 13,564 | |
| Derivative instruments | | | 48,018 | | | | 4,354 | |
| Operating lease right-of-use assets | | | 12,362 | | | | 5,136 | |
| Other long-term assets | | | 35,577 | | | | 38,449 | |
| Total assets | | $ | 2,065,137 | | | $ | 1,900,525 | |
| Liabilities and Equity | | | | | | | | |
Current liabilities | | | | | | | | |
| Accounts payable and accrued expenses | | $ | 272,637 | | | $ | 340,393 | |
| Current portion of long-term debt | | | 113,773 | | | | 717 | |
| Derivative instruments | | | 98 | | | | 99,302 | |
| Current portion of asset retirement obligation | | | 7,282 | | | | 5,060 | |
| Operating lease obligations - current | | | 841 | | | | 3,606 | |
| Total current liabilities | | | 394,631 | | | | 449,078 | |
Long-term debt | | | 697,405 | | | | 411,920 | |
Derivative instruments | | | 3,994 | | | | 8,330 | |
Asset retirement obligation | | | 242,391 | | | | 248,221 | |
Operating lease obligations - noncurrent | | | 25,316 | | | | 2,112 | |
Other long-term liabilities | | | 29,501 | | | | 25,715 | |
| Total liabilities | | | 1,393,238 | | | | 1,145,376 | |
Members’ equity | | | 671,899 | | | | 755,148 | |
| | | | | | | | | |
Total liabilities and equity | | $ | 2,065,137 | | | $ | 1,900,525 | |
The accompanying notes are an integral part of these consolidated financial statements.
| (in thousands of dollars) | | Twelve Months Ended December 31, | |
| Revenues and other income items | | 2023 | | | 2022 | |
| | | | | | |
| Oil revenues | | $ | 619,524 | | | $ | 720,668 | |
| Natural gas revenues | | | 161,054 | | | | 413,234 | |
| NGL revenues | | | 113,320 | | | | 202,239 | |
| Oil, natural gas and NGL revenues | | | 893,898 | | | | 1,336,141 | |
| Gain (loss) on commodity derivative instruments | | | 145,934 | | | | (262,083 | ) |
| Other revenues, net | | | 83,492 | | | | 106,945 | |
| Total revenues and other income items | | | 1,123,324 | | | | 1,181,003 | |
| Operating costs and expenses | | | | | | | | |
| Operating costs | | | 488,261 | | | | 576,482 | |
| Depletion, depreciation and amortization | | | 166,488 | | | | 148,659 | |
| Impairment of oil and natural gas properties | | | 66,785 | | | | 118,839 | |
| General and administrative expenses | | | 83,318 | | | | 61,326 | |
| Restructuring costs | | | 1,631 | | | | 283 | |
| (Gain) loss on sale of assets | | | (1,090 | ) | | | (1,142 | ) |
| Total operating costs and expenses | | | 805,393 | | | | 904,447 | |
| Operating income | | | 317,931
| | | | 276,556
| |
Interest expense | | | 62,176 | | | | 25,109 | |
Other income, net | | | (1,130 | ) | | | (230 | ) |
| Total other expense (income) | | | 61,046 | | | | 24,879 | |
| Income before taxes | | | 256,885 | | | | 251,677 | |
Income tax expense (benefit) | | | 604 | | | | 1,070 | |
| Net income | | $ | 256,281 | | | $ | 250,607 | |
The accompanying notes are an integral part of these consolidated financial statements.
| (in thousands of dollars) | | Outstanding Common Units | | | Common Equity | | | Total Members’ Equity | |
| |
| Balances, December 31, 2021 | | | | | | | | | |
| | | 2,894 | | | $ | 624,567 | | | $ | 624,567 | |
Unit-based compensation | | | – | | | | 256 | | | | 256 | |
Units issued under unit-based compensation awards, net of tax withholdings
| | | 2 | | | | (57 | ) | | | (57 | ) |
Net income | | | – | | | | 250,607 | | | | 250,607 | |
Redemption of units | | | – | | | | (21 | ) | | | (21 | ) |
Distributions | | | – | | | | (120,000 | ) | | | (120,000 | ) |
Other | | | – | | | | (204 | ) | | | (204 | ) |
| Balances, December 31, 2022 | | | 2,896 | | | $ | 755,148 | | | $ | 755,148 | |
Unit-based compensation | | | – | | | | 327 | | | | 327 | |
Units issued under unit-based compensation awards, net of tax withholdings
| | | 2 | | | | 1,987 | | | | 1,987 | |
Net income | | | – | | | | 256,281 | | | | 256,281 | |
Redemption of units | | | (1 | ) | | | (1,548 | ) | | | (1,548 | ) |
Distributions | | | – | | | | (340,000 | ) | | | (340,000 | ) |
Other | | | – | | | | (296 | ) | | | (296 | ) |
| Balances, December 31, 2023 | | | 2,897 | | | $ | 671,899 | | | $ | 671,899 | |
The accompanying notes are an integral part of these consolidated financial statements.
| | | Twelve Months Ended December 31, | |
| Thousands of dollars | | 2023 | | | 2022 | |
| Cash flows from operating activities | | | | | | |
| Net income | | $ | 256,281 | | | $ | 250,607 | |
| Adjustments to reconcile cash flow from operating activities: | | | | | | | | |
| Depletion, depreciation and amortization | | | 166,488 | | | | 148,659 | |
| Impairment of oil and natural gas properties | | | 66,785 | | | | 118,839 | |
| (Gain) loss on derivative instruments | | | (145,934 | ) | | | 262,083 | |
| Derivative instrument settlement payments | | | (46,722 | ) | | | (370,798 | ) |
| Deferred income taxes | | | (13 | ) | | | (41 | ) |
| Loss (gain) on sale of assets | | | (1,090 | ) | | | (1,142 | ) |
| Restructuring costs, net of payments | | | 124 | | | | 124 | |
| Write-off of debt issuance costs | | | 5,649 | | | | 2,374 | |
| Other | | | 5,594 | | | | 14,846 | |
| Changes in assets and liabilities: | | | | | | |
| |
| Accounts receivable and other assets | | | 48,621 | | | | (73,512 | ) |
| Inventory | | | (403 | ) | | | (249 | ) |
| Accounts payable and accrued expenses | | | (47,119 | ) | | | 78,153 | |
Net cash provided by (used in) operating activities | | | 308,261 | | | | 429,943 | |
| Cash flows from investing activities | | | | | | | | |
| Capital acquisitions, net | | | (17,968 | ) | | | (544,065 | ) |
| Capital expenditures | | | (286,420 | ) | | | (241,633 | ) |
| Proceeds from sale of assets | | | 15,514 | | | | 10,082 | |
Net cash provided by (used in) investing activities | | | (288,874 | ) | | | (775,616 | ) |
| Cash flows from financing activities | | | | | | | | |
| Distributions to common unitholders | | | (340,000 | ) | | | (120,000 | ) |
| Credit facility borrowings | | | 355,000 | | | | 753,000 | |
| Repayments of credit facility | | | (575,000 | ) | | | (343,000 | ) |
| Issuance of term debt | | | 630,000 | | | | (22,250 | ) |
| Long-term debt issuance costs | | | (18,488 | ) | | | - | |
| Redemption of common units | | | (1,548 | ) | | | (507 | ) |
| Principal payments on finance lease obligations | | | (958 | ) | | | (375 | ) |
| Other | | | - | | | | (204 | ) |
Net cash (used in) provided by financing activities | | | 49,006 | | | | 266,664 | |
| (Decrease) increase in cash and restricted cash | | | 68,393 | | | | (79,009 | ) |
| Cash and restricted cash - beginning of period | | | 16,806 | | | | 95,815 | |
Cash and restricted cash - end of period | | $ | 85,199 | | | $ | 16,806 | |
The accompanying notes are an integral part of these consolidated financial statements.
Maverick Natural Resources, LLC (“MNR” or “Parent”) and its subsidiaries, including Maverick Asset Holdings LLC (“MAH”), newly formed Maverick ABS Holdco, LLC (“ABS Holdco”), and Maverick Services, LLC (“MAV Services”), (collectively, “Maverick,” “we” or the “Company”) is a Delaware limited liability company formed on March 22, 2018. We are a Houston, Texas-based oil and natural gas company focused on the development and production of long-lived oil and natural gas reserves throughout the United States. Our primary operations are in seven regions in the United States: East Texas, Mid-Continent (Western Oklahoma and Eastern New Mexico); Permian (West Texas); Rockies (Wyoming); Southeast (Southwest Florida, Florida Panhandle and Alabama); and Western Anadarko (Texas Panhandle and Southwestern Oklahoma).
On October 26, 2023, the Parent, through its consolidated subsidiaries, raised $640 million through an asset-backed securitization financing transaction.
Several new subsidiaries were created including MNR ABS Holdings I, LLC (“ABS Holdings”) and MNR ABS Issuer I, LLC (“ABS Issuer”). See Note 4 – Acquisitions and Divestitures – Transactions Between Entities Under Common Control and Note 10 – Debt for further discussion.
During 2022, the Company acquired certain producing properties in the Permian Basin and in the Western Anadarko Basin from two separate oil and gas companies in separate transactions. See Note 4 for further discussion.
During 2022, the Company divested properties in and the Midwest region. Certain Midwest divestitures resulted in the deconsolidation of entities. See Note 4 – Acquisitions and Divestitures for further discussion.
The Company operates its properties through its primary operating subsidiaries: Breitburn Operating, L.P. (“BOLP”), Unbridled Resources, LLC (“Unbridled”), and Maverick Permian, LLC.
In addition to our operating companies, the Company’s subsidiaries include: (i) Wheeler Midstream, LLC, an oil terminal located in Wheeler County, TX, which purchases oil from both properties operated by Unbridled, a wholly owned entity, and third-party operated properties, (ii) MidPoint Midstream, LLC, a gas gathering operation located in Wheeler and Hemphill Counties, Texas and Roger Mills and Beckham Counties, Oklahoma, which gathers and compresses natural gas produced from Unbridled and third party operated properties, and (iii) Bluebonnet Resources, LLC, which acquired unproved acreage for development purposes.
| 2. | Summary of Significant Accounting Policies |
Basis of Presentation and Principles of Consolidation
Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). Our consolidated financial statements include Maverick and our wholly owned or majority-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
Recently Adopted Accounting Standards
In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13’’), which changes the impairment model for most financial assets. The ASU introduces a new credit loss methodology, Current Expected Credit Losses (CECL), which requires earlier recognition of credit losses, while also providing additional transparency about credit risk. Since its original issuance in 2016, the FASB has issued several updates to the original ASU. The CECL framework utilizes a lifetime “expected credit loss” measurement objective for the recognition of credit losses for loans, held-to-maturity securities, and other receivables at the time the financial asset is originated or acquired. The expected credit losses are adjusted each period for changes in expected lifetime credit losses. The methodology replaces the multiple existing impairment methods, which generally require that a loss be incurred before it is recognized.
On January 1, 2023, the Company adopted the guidance applying the modified retrospective basis approach. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements as of the adoption date, January 1, 2023.
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”), which provided optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that referenced LIBOR (“London Inter-Bank Offered Rate”) or another rate. ASU 2020-04 was in effect through December 31, 2022. In January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. In December 2022, the FASB issued ASU 2022-06, “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848” (“ASU 2022-06”), which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. As of December 31, 2023, the Company’s borrowings under its Credit Facility bear interest at an ABR or SOFR basis plus an applicable margin and the ABS loans have a fixed interest rate. At this time, the Company does not plan to enter into additional contracts using LIBOR as a reference rate. For additional information, see Note 10 – Debt.
In October 2021, the FASB issued ASU 2021-07, “Compensation – Stock Compensation (Topic 718): Determining the Current Price of an Underlying Share for Equity-Classified Share-Based Awards” as a practical expedient to allow a nonpublic entity to determine the current price input of equity-classified share-based awards issued to both employees and nonemployees using the reasonable application of a reasonable valuation method. The practical expedient describes the characteristics of the reasonable application of a reasonable valuation method as the same characteristics used in the regulations of the U.S. Department of Treasury for income tax purposes (the “Treasury Regulations”). Consequently, a reasonable valuation performed in accordance with the Treasury Regulations is an example of a way to achieve the practical expedient. This accounting standard had no effect on the Company and the company continues to use a reasonable valuation method for its equity classified awards.
Significant Recent Accounting Standards Issued Not Yet Adopted
In March 2023, the FASB issued an ASU to amend certain provisions of ASC 842 that apply to arrangements between related parties under common control. The ASU amends the accounting for the amortization period of leasehold improvements in common-control leases for all entities and requires certain disclosures when the lease term is shorter than the useful life of the asset. This ASU is effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years. Early adoption is permitted. We do not expect the application of this ASU to have a material impact on our consolidated financial statements or disclosures.
Use of Estimates
The preparation of financial statements and related footnotes in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Our significant estimates include oil and natural gas reserves; cash flow estimates used in impairment testing of oil and natural gas properties and midstream assets; depreciation, depletion, amortization (“DD&A”) and accretion; asset retirement obligations (“ARO”); accrued revenue and related receivables; operating expenses and accrued liabilities; valuation of liability-classified incentive awards; mark-to-market hedge valuations; and unit-based compensation. We believe our estimates are reasonable, and actual results could differ significantly from these estimates.
Cash and Restricted Cash
Our cash consists of cash in the bank. Current restricted cash represents funds held in escrow that will be used to settle certain general unsecured claims related to the 2018 bankruptcy and cash held in a liquidity reserve account and collection account maintained in connection with the ABS Financing Transaction. At December 31, 2023, the amounts in Restricted Cash consisted of $3.2 million, $23.6 million and $5.1 million for the escrow, liquidity reserve and collection accounts, respectively. At December 31, 2022, the escrow account had a balance of $3.2 million. The liquidity reserve and the collection account did not have a balance at December 31, 2022. Long-term restricted cash represents funds held for future development costs and abandonment obligations at the Jay field. See Note 8 – Other Long-Term Assets for further discussion.
Revenue Recognition and Natural Gas Balancing
We recognize revenues from the sale of oil, natural gas and natural gas liquid (“NGL”) when control of the oil, natural gas and NGL production has transferred to the customer, the transaction price has been determined and collectability is reasonably assured and evidenced by a contract. Performance obligations under our contracts with customers are typically satisfied when oil, natural gas and NGL are transferred through delivery at the inlet of pipeline or processing plant, onloading to the delivery truck or barge.
Oil terminal revenues are recognized when delivery to the purchaser has occurred, title has transferred, and the associated receivable is recoverable.
We generate gathering revenues by providing gathering and compression services to third parties. We recognize revenue for these arrangements over time based on a per unit rate applied to volumes that travel through the gathering system. In addition, we retain any drip liquids collected on our gathering systems. The value of these drip liquids is recognized as part of gathering revenue in the month the underlying gathering service is provided based upon the price realized for sale of drip condensate to third party customers which represents a market price.
Natural gas production imbalances represent the fair value of amounts payable or receivable for natural gas production imbalances, and revenues are recognized based on our share of volumes sold, regardless of whether we have taken our proportional share of volume produced. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2023 and 2022, our natural gas production imbalance asset of $3.1 million and $3.0 million, respectively, was included in other long-term assets and natural gas production imbalance liability of $21.8 million and $23.9 million, respectively, was included in other long-term liabilities on our consolidated balance sheets.
Inventory
Inventory represents our share of crude oil produced from our Florida and Texas operations that is held in storage tanks and unsold at the end of the period. Inventory is reported as current assets in our consolidated balance sheets and carried at the lower of cost or market. We assess the carrying value of our inventory periodically to determine any adjustments necessary to reduce the carrying value to net realizable value. Uncertainties that may impact our assessment include: the applicable quality and location differentials and changes in the timing of a sale. We did not recognize any write-downs during the periods presented.
Property, Plant and Equipment
Proved Oil and Natural Gas Properties
We account for oil and natural gas exploration and development activities using the successful efforts method. Under this method, all property acquisition and development costs are capitalized when incurred and depleted on a unit-of-production basis over total proved reserves and proved developed reserves, respectively. Proved leasehold costs associated with proved reserves are depleted based on total proved reserves, which include proved undeveloped reserves.
Costs of retired, sold or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently in the consolidated statements of operations.
Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.
Unproved Oil and Natural Gas Properties
Unproved oil and natural gas properties include lease acquisition costs which are costs incurred to acquire unproved leases. Lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated lease acquisition costs. Lease acquisition costs that are expensed are recorded as “impairment of oil and natural gas properties” in our consolidated statements of operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as recovery of costs unless the proceeds exceed the entire cost of the property.
Impairment of Oil and Natural Gas Properties
We evaluate proved oil and natural gas properties for impairment whenever facts or circumstances indicate that the carrying values of such properties may not be recoverable. We perform impairment assessments by grouping assets at the lowest level for which there are identifiable cash flows. Impairment is indicated when a triggering event occurs and/or the sum of the estimated future net cash flows of an evaluated asset group is less than the asset group’s carrying value. Triggering events may include potential disposition of assets and declines in oil, natural gas and NGL prices. If impairment is indicated, we estimate fair value using a discounted cash flow approach. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with risk and current market conditions associated with realizing the expected cash flows projected.
We evaluate unproved oil and natural gas properties periodically for impairment on a geographic basis based on remaining lease terms, drilling results or future plans to develop acreage. These factors may be affected by economic factors including future oil and natural gas prices and projected capital costs.
We evaluate the recovery of our other property, plant and equipment whenever events or circumstances indicate a decline in the recoverability of the respective carrying values may have occurred. We compare the net carrying value of the asset group to the undiscounted net cash flows projected. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount to fair value.
Impairment expense for proved and unproved properties is reported as “impairment of oil and natural gas properties” in the consolidated statements of operations. Impairment expense for other property, plant and equipment is reported as “impairment of long-lived assets” in the consolidated statements of operations.
Other Property, Plant and Equipment
Other property, plant and equipment include buildings, field equipment, compressors, furniture, leasehold improvements, computer hardware and software. We record other property, plant and equipment at cost and depreciate the assets on the straight-line method over the estimated lives of the individual assets.
We assign the useful lives of our property, plant and equipment based upon our internal estimates that are reviewed by management periodically. We use estimated lives of 20 years for our buildings, two to seven years for field equipment, furniture and computer hardware and software, and the remaining lease term for leasehold improvements. At the time of sale or disposal, the costs and accumulated DD&A of the sold or disposed assets are removed from our consolidated balance sheets with any gain or loss realized in our consolidated statements of operations.
Midstream Assets
Midstream assets consist primarily of natural gas gathering and pipelines, as well as an oil terminal. Renewals and betterments, which substantially extend the useful lives of the assets, are capitalized and reported as other property, plant and equipment in our consolidated balance sheets. Maintenance and repairs are expensed when incurred. These assets are depreciated on the straight-line method over 3 to 30 years. We consider estimated future dismantlement, restoration and abandonment costs in our calculation of straight-line DD&A for our natural gas gathering, processing facilities and pipelines.
Leases
At inception, contracts are assessed for the presence of a lease according to the criteria prescribed by Accounting Standards Codification (“ASC”) Topic 842, “Leases” (“ASC 842”). If a lease is present, further criteria is assessed to determine if the lease should be classified as an operating or finance lease. Operating leases are presented on the consolidated balance sheet as Operating lease right-of-use assets with the corresponding lease liabilities presented as Operating lease obligations – current and Operating lease obligations‑noncurrent. Finance lease assets are presented on the consolidated balance sheet as Other property, plant and equipment with the corresponding liabilities presented in Current portion of long-term debt and Long-term debt.
Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term. Lease assets are then recognized based on the value of the lease liabilities. For leases where the implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates.
Operating leases are expensed according to their nature and recognized in Operating expenses or General and administrative expenses. Finance leases are depreciated and amortized with the relevant expenses recognized in Depreciation, Depletion and Amortization and Interest Expense on the consolidated statement of operations. See Note 6 – Leases for further discussion.
Revenue and Production Taxes Payable
We calculate and pay taxes and royalties on crude oil and natural gas in accordance with particular contractual provisions of the leases, license or concession agreements and the laws and regulations applicable to those agreements.
Asset Retirement Obligations
We recognize estimated liabilities for future costs associated with the abandonment of our oil and natural gas properties, gas gathering, processing facilities and pipelines. We record a liability for the fair value of an ARO and a corresponding increase to the carrying value of the related long-lived asset in the period in which wells are drilled or acquired. See Note 11 – Asset Retirement Obligations for further discussion.
Liability-Classified Awards
We classify certain awards that will be settled in cash as liability awards in our balance sheet in accounts payable and accrued expenses. The fair value of a liability-classified award is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general and administrative expense and operating costs over the vesting period of the award. The Company’s liability-classified awards include a performance condition based on preceding Implied Equity Value (as defined in Note 14 – Compensation). See Note 5 – Financial Instruments and Fair Value Measurements for further discussion.
Unit-Based Compensation
Unit-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards is recognized on a straight-line basis over the requisite service period. See Note 14 – Compensation for further discussion.
Environmental Liabilities
We are subject to federal, state and local environmental laws and regulations. These laws regulate the release, disposal or discharge of materials into the environment or otherwise relate to environmental protection. These laws and regulations may require that we remove or mitigate the environmental effect of the discharge, disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. We expense expenditures related to an existing condition caused by past operations that have no future economic benefit. We record liabilities for noncapital expenditures when environmental assessments or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability is fixed or determinable. We did not have environmental liabilities at December 31, 2023 and December 31, 2022, respectively.
Business Combinations and Asset Acquisitions
We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition-date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.
We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of the proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average costs of capital rate are subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of oil and natural gas properties within the same regions and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into exchange for such properties.
Any excess of the acquisition price over the estimated fair value of net assets acquired in recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded as a bargain purchase gain in other income, net on our consolidated statements of operations.
In an asset acquisition, transaction costs are capitalized, and any excess or deficit of fair value of net assets in relation to acquisition price is allocated to the acquired assets based on the relative fair value.
Commitments and Contingencies
We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine that it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the mostly likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss.
Fair Value of Financial Instruments
Certain of our financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Our financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 5 – Financial Instruments and Fair Value Measurements for additional details.
Fair Value of Nonfinancial Assets and Liabilities
We apply fair value accounting guidance to measure our nonfinancial assets and liabilities such as those obtained through property, plant and equipment, AROs and restructuring. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production and other applicable sales estimates, operational costs and risk-adjusted discount rate. We may use the present value of estimated future cash inflows and outflows, third-party offers or prices of comparable assets with consideration of the current market conditions to value our nonfinancial assets and liabilities when circumstances dictate fair value determination is necessary.
Concentrations of Credit Risk
We are subject to credit risk resulting from the concentration of our oil, natural gas and NGL receivables with the following major purchasers that accounted for 10% or more of our total oil, natural gas and NGL sales for the periods presented:
| | | Twelve Months Ended December 31, | |
| Purchaser | | 2023 | | | 2022 | |
| Customer A | | | 15 | % | | | N/A | |
| Customer B | | | 12 | % | | | 12 | % |
| Customer C | | | 11 | % | | | 19 | % |
Our financial instruments with credit risk exposure consist principally of cash and cash equivalents, accounts receivable, and derivative instruments. We maintain cash and cash equivalents in deposit accounts at financial institutions that may exceed the federally insured limits. We monitor credit risk exposure by (i) placing our assets and other financial instruments with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include our evaluation of customers’ financial condition and monitoring payment history and (iii) netting derivative assets and liabilities where we have legal right of offset with counterparties and diversifying our derivative instrument portfolio.
Risk Management and Derivative Instruments
We have entered into derivative contracts with counterparties to reduce the effect of changes in oil and natural gas prices on a portion of our oil and natural gas production. We do not enter into such contracts for speculative trading purposes. Our commodity derivative instruments are measured at fair value in our consolidated balance sheets as derivative assets or derivative liabilities. We have not designated any derivative instruments as hedges for accounting purposes. Gains and losses from valuation changes in commodity derivatives are reported as (gain) loss on commodity derivative instruments in our consolidated statements of operations. Our cash flows are only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. Cash settlements are reflected as operating activities in our consolidated statements of cash flows. We expense transaction costs related to the modification of derivative instruments as incurred. See Note 5 – Financial Instruments and Fair Value Measurements for further discussion of our derivative instruments.
We have market and credit risk exposure due to commodity derivatives that are concentrated with certain counterparties who are affiliate lenders under the Credit Agreement. We believe the risk of nonperformance by our counterparties is low as we execute our derivative contracts only with credit-worthy financial institutions and we have no past-due receivables from our derivative counterparties. As of December 31, 2023, our largest derivative counterparties were Citizens Bank N.A., Key Bank National Association, J. ARON & Company, and JP Morgan Chase Bank N.A., which accounted for approximately 58.22%, 18.80%, 16.65%, and 6.33%, respectively, of our derivative settlement payable balance of $8.9 million.
Our commodity derivative contracts are documented with industry standard contracts known as Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. We are not required to provide any credit support to our counterparties other than cross collateralization with the oil and natural gas properties securing the Credit Agreement. We have certain limitations under the Credit Agreement, including a provision that limits the total amount of our production that may be hedged to certain percentages of current and forecasted production. As of December 31, 2023, we were in compliance with these limitations. See Note 5 – Financial Instruments and Fair Value Measurements and Note 10 – Debt for additional information.
Debt Issuance Costs
Debt issuance costs related to our Credit Facility and ABS Notes are amortized over the life of the related debt using the effective interest rate method and unamortized debt issuance costs are netted against the outstanding balance of debt obligations on our consolidated balance sheets. Any unamortized costs associated with retired debt are written off and included in the determination of gain or loss on extinguishment of debt.
Revenues
Sales of oil, natural gas and NGL are recognized at the point when control of the commodity is transferred to the customer and collectability is reasonably assured. Most of our contracts’ pricing provisions are tied to a commodity market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas and NGL fluctuates to remain competitive with the other available oil, natural gas and NGL suppliers.
Oil Sales
Under our crude purchase and marketing contracts, we generally sell oil production at the wellhead and collect an agreed-upon index price, net of pricing differentials. We recognize revenue when control transfers to the purchaser at the wellhead or delivery point for onloading to delivery truck or barge at the net price received.
Natural Gas and NGL Sales
Under our natural gas gathering, processing and purchase contracts, we deliver unprocessed natural gas to processing plants at the wellhead or the inlet of the processing plant’s system. The midstream entity then gathers and processes the natural gas to produce residue gas and NGLs generated from processing. In the majority of cases, the midstream entity remits payment to us for NGLs based on index-based pricing or weighted average sales proceeds less deductions which may include gathering, processing and transportation fees, while the residue gas is redelivered to us at the tailgate of the midstream entity’s processing plant for marketing under separate contracts. We sell residue gas at the delivery point specified in the separate contract and collect an agreed-upon index price, net of pricing differentials. Transportation, gathering and processing costs incurred after control transfers to the purchaser are recognized as reductions to revenues rather than as operating costs.
Oil Terminal Sales
Under our oil terminal sales contracts, we sell oil at the delivery point specified in the contract and collect an agreed-upon index price, net of pricing differentials. Control as defined under ASC 606, “Revenue from Contracts with Customers” (“ASC 606”) passes at the delivery point. The delivery point is the point at which the oil passes the last permanent delivery flange or meter connecting our facility to customer’s facility. At the delivery point, the customer takes physical custody, title and risk of loss of the product and we have a right to receive payment for the sale. We recognize revenue at the net price received when control transfers to the customer. Oil terminal sales are reported in other revenues, net on our consolidated statements of operations.
Gathering Revenue
We generate gathering revenues by providing gathering and compression services to third parties, which are reported in other revenues on our consolidated statement of operations. We recognize revenue for these arrangements over time based on a per unit rate applied to volumes that travel through the gathering system. In addition, we retain any drip liquids collected on our gathering systems. The value of these drip liquids is recognized as part of gathering revenue in the month the underlying gathering service is provided based upon the price realized for sale of drip condensate to third party customers which represents a market price.
Purchased Condensate Sales
The Company’s purchased oil and natural gas sales are derived from the sale of oil and natural gas purchased from a third party and reported in other revenues, net on our consolidated statements of operations. Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased oil or natural gas before it is transferred to the customer.
Performance Obligations
A significant number of our product sales are short-term in nature with a contract term of one year or less. We record revenue on our oil, natural gas and NGL sales at the time production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 90 days after the production is delivered.
We have elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation; (ii) contracts with an original expected duration of one year or less; and (iii) contracts for which we recognize revenue under the right to invoice practical expedient.
Contract Balances
We invoice our customers when we have satisfied our performance obligations, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC 606.
Accounts Receivable and Allowance for Credit Losses
Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to third party purchasers. Accounts receivable is held at cost. At each reporting date, the Company assesses the expected lifetime credit losses on initial recognition of accounts receivable. At December 31, 2023, the credit loss allowance on accounts receivable from joint interest owners was $5.8 million, and the Company recorded $0.6 million of credit losses during 2023. At December 31, 2023, no credit loss allowance existed on revenue accounts receivable, and no credit losses were recorded during the period.
| 3. | Supplemental Cash Flow Information |
Supplemental disclosures to the consolidated statements of cash flows are presented below:
| | | Twelve Months Ended December 31, | |
| |
(in thousands of dollars) | | 2023 | | | 2022 | |
Cash payments | | | | | | |
| Interest | | $ | 34,799 | | | $ | 12,927 | |
Noncash investing activities | | | | | | | | |
(Increase) decrease in accrued capital expenditures | | $ | (10,809 | ) | | $ | 34,081 | |
| (Increase) in asset retirement obligations | | | (11,202 | ) | | | (3,804 | ) |
| Increase in assets under operating leases | | | (10,928 | ) | | | (3,032 | ) |
| Decrease in liabilities for asset divestitures | | | (1,545 | ) | | | (1,015 | ) |
| Asset retirement obligations assumed | | | - | | | | 22,917 | |
| Noncash financing activities | | | | | | | | |
| Increase in assets under finance leases | | | (1,876 | ) | | | (2,982 | ) |
| Reconciliation of cash, cash equivalents, and restricted | | | | | | | | |
| cash reported in the consolidated balance sheets | | | | | | | | |
| Cash and cash equivalents | | $ | 53,263 | | | $ | 10 | |
| Restricted cash | | | 31,936 | | | | 16,796 | |
| Total cash, cash equivalents, and restricted cash | | | | | | | | |
| shown in the statement of cash flows | | $ | 85,199 | | | $ | 16,806 | |
| 4. | Acquisitions and Divestitures |
Acquisitions
In January 2022, we entered into a definitive agreement to acquire certain producing properties in the Permian Basin from a large independent oil and gas company for a purchase price of $440 million, subject to customary adjustments (the “Permian Acquisition”). The acquisition was accounted for as a business combination. Through December 31, 2022, the purchase price allocation was adjusted as shown in the table below. These adjustments have been retrospectively reflected as of the acquisition date. This transaction closed in April 2022 and related transaction costs were $0.4 million.
The following table summarizes the net assets acquired from the Permian Acquisition.
| (in thousands of dollars) | | Permian Acquisition | |
| Net assets purchased | | | |
| Oil and gas properties | | $ | 379,867 | |
| Other property, plant, and equipment | | | 7,460 | |
| Asset retirement obligation | | | (19,486 | ) |
| Working capital adjustments | | | 1,773 | |
| Fair value of net assets | | $ | 369,614 | |
| Consideration | | | | |
| Purchase price | | $ | 440,000 | |
| Pre-close adjustments | | | (70,386 | ) |
Total consideration and post purchase price adjustments | | | 369,614 | |
Deposit paid in January 2022 | | | (33,000 | ) |
Total consideration and post purchase price adjustments, net of deposit paid | | $ | 336,614
| |
In May 2022, we entered into a definitive agreement to acquire certain producing properties in the Western Anadarko Basin from a large independent oil and gas company for a purchase price of $180 million, subject to customary adjustments (the “Anadarko Acquisition”). The acquisition was accounted for as a business combination. Through December 31, 2022, the purchase price allocation was adjusted as shown in the table below. These adjustments have been retrospectively reflected as of the acquisition date. This transaction closed in June 2022.
The following table summarizes the net assets acquired from the Anadarko Acquisition.
| (in thousands of dollars) | | Anadarko Acquisition | |
| |
| Net assets purchased | | | |
| Oil and gas properties | | $ | 170,580 | |
| Asset retirement obligation | | | (3,430 | ) |
| Working capital adjustments | | | (550 | ) |
| Fair value of net assets | | $ | 166,600 | |
| Consideration | | | | |
| Purchase price | | $ | 180,000 | |
| Pre-close adjustments | | | (13,400 | ) |
| Total consideration and post purchase price adjustments | | $ | 166,600 | |
Both acquisitions were funded by a fully committed $750 million reserve-based loan provided by a syndicate of banks, see further details in Note 10 – Debt.
During 2023, we acquired approximately 25,000 net acres of unproved acreage in Texas for total consideration of $14.6 million. The acquisition was financed through borrowings under our existing credit facility. The acreage is considered strategic to the Company’s long-term growth objectives and is expected to provide significant opportunities for exploration and development. These leases are currently in the early stages of evaluation.
Transactions Between Entities Under Common Control
On October 26, 2023, Unbridled entered into an asset purchase agreement with ABS Issuer (the “Purchase and Sale Agreement”). Unbridled agreed to sell and transfer to ABS Issuer certain operated and non-operated oil and natural gas wells and all oil and natural gas leases, subleases and leasehold covering such wells (the “ABS Assets” and such transfer, the “ABS Asset Transfer”) for a purchase price of $640 million, of which $630 million was cash and $10 million was a non-cash note payable. In connection with the ABS Asset Transfer, MAH transferred by novation to the ABS Issuer certain hedge agreements (“Assumed Hedges”).
In connection with the transaction, ABS Issuer entered into an indenture with UMB Bank, N.A. as indenture trustee (the “Indenture Trustee”) (the “Indenture”) to which ABS Issuer issued (a) $640 million aggregate principal amount of Series 2023-1 Notes, consisting of (i) $285 million aggregate principal amount of its 8.121% Series 2023-1 Notes, Class A-1 Notes due December 2038, (ii) $260 million aggregate principal amount of its 8.946% Series 2023-1 Notes, Class A-2 Notes due December 2038 and (iii) $95 million aggregate principal amount of its 12.436% Series 2023-1 Notes, Class B Notes due December 2038 (collectively, the “ABS Notes”) and (b) pledged the ABS Assets to the Indenture Trustee to secure the ABS Issuer’s obligations under the Indenture (the “ABS Financing Transaction”).
In addition the following events occurred in connection with the transaction: (i) $10 million of the ABS Notes were issued to Maverick, (ii) a holdback of $5.4 million related to consents not received at the date of the transaction which is reflected as restricted cash, (iii) a Liquidity Reserve Account was established for $23.6 million and is reflected as restricted cash, (iv) $260 million was an equity distribution and (v) repaid $300 million for the Credit Facility held by MAH.
We incurred hedge novation fees of $4.6 million in conjunction with the ABS Financing Transaction which were expensed as incurred in general and administrative expenses in our consolidated statement of operations. We incurred $12.7 million of costs including legal fees and administrative fees in connection with the ABS Financing Transaction which were capitalized as deferred financing costs and recorded as an offset to the carrying value of the ABS Notes. See Note 10 – Debt for more information regarding the ABS Notes.
Divestitures
In March 2023, we entered into an agreement with a third party to divest certain interests in oil and natural gas properties, rights and related assets in Western Anadarko Basin for a purchase price of $10.0 million. This sale was accounted for as a normal retirement under the provisions of paragraph ASC 932-360-40-3 with no gain or loss recorded on the sale for the year ended December 31, 2023.
In May 2023, we entered into an agreement with a third party to divest certain properties in west Texas for a purchase price of $4.5 million. We recognized a $0.3 million gain on the sale for the year ended December 31, 2023.
In November 2023, we entered into an agreement with a third party to divest certain interests in oil and natural gas properties, rights and related assets in Wyoming for a purchase price of $0. We recognized a $0.1 million gain on the sale for the year ended December 31, 2023.
In connection with other divestitures of non-core oil and natural gas properties, we recognized gains of $1.1 million in “gain (loss) on sale of assets” on our consolidated statements of operations for the year ended December 31, 2023.
In June 2022, we entered into an agreement with a third party to divest certain interests in oil and natural gas properties, rights and related assets in areas located in Michigan for a purchase price total of $6.0 million. As of June 30, 2022, we classified these as held for sale and we recognized an impairment charge on the properties of $12.0 million for the year-ended December 31, 2022. The transaction closed in August 2022, and we incurred a gain on this sale of $3.3 million for the year ended December 31, 2022.
In January 2022, we divested the Beaver Creek Interests and deconsolidated Beaver Creek, L.L.C. We incurred a loss $1.0 million in connection with this divestiture for the year ended December 31, 2022.
In connection with other divestitures, we recognized gains of $1.2 million in “gain (loss) on sale of assets” on our consolidated statements of operations for the year ended December 31, 2022.
| 5. | Financial Instruments and Fair Value Measurements |
Commodity Activities
At December 31, 2023, our commodity derivatives consisted of fixed price swaps and two-way costless collars. Our fixed price swaps are comprised of a sold call and a purchased put established at the same price (both ceiling and floor). The two-way collars are a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling). For both swaps and collars, all transactions are settled in cash for the net difference between settlement and contract prices, multiplied by the hedged contract volumes, for the settlement period.
In October 2023, MAH novated to ABS Issuer certain derivative contracts underlying certain derivative instruments in connection with the ABS Financing Transaction. These derivative contracts consisted of fixed-price oil, natural gas and NGL swaps and collars. As a party to these contracts, ABS Issuer received payments directly from the counterparty or paid any amounts owed directly to the counterparty. Settlement of the novated commodity derivative contracts continued through the date the commodity derivatives instruments were unwound. Costs associated with the novation of $4.6 million were expensed as incurred in general and administrative expenses.
Our commodity derivative contracts settle monthly based on the differential between the contract price and the average NYMEX West Texas Intermediate index price (“NYMEX WTI”) (oil), average NYMEX Henry Hub index price (“NYMEX HH”) (natural gas) and Mont Belvieu Oil Price Information Service (“OPIS”) (NGLs). The following table presents derivative positions for the periods indicated as of December 31, 2023:
| | | 2024 | | | 2025 | | | 2026 | | | 2027 | | | 2028 | | | 2029 | | | 2030 | |
| Oil Positions | | | | | | | | | | | | | | | | | | | | | |
| Fixed Price Swaps - NYMEX WTI | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 11,047 | | | | 12,226 | | | | 10,873 | | | | 3,688 | | | | 3,366 | | | | - | | | | - | |
| Average Price ($/Bbl) | | $ | 72.10 | | | $ | 71.85 | | | $ | 68.45 | | | $ | 65.95 | | | $ | 62.21 | | | $ | - | | | $ | - | |
| Fixed Price Swaps - NYMEX BRENT | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Average Price ($/Bbl) | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Costless Collar - NYMEX WTI | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 4,307 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Average Put Price ($/Bbl) | | $ | 63.71 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Average Call Price ($/Bbl) | | $ | 88.96 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 15,354 | | | | 12,226 | | | | 10,873 | | | | 3,688 | | | | 3,366 | | | | - | | | | - | |
| Average Price ($/Bbl) | | $ | 73.29 | | | $ | 71.85 | | | $ | 68.45 | | | $ | 65.95 | | | $ | 62.21 | | | $ | - | | | $ | - | |
| Gas Positions | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Price Swaps - Henry Hub | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (MMBtu/d) | | | 87,361 | | | | 120,838 | | | | 99,514 | | | | 69,070 | | | | 61,056 | | | | 50,962 | | | | 47,714 | |
| Average Price ($/MMBtu) | | $ | 3.42 | | | $ | 3.90 | | | $ | 3.89 | | | $ | 3.76 | | | $ | 3.63 | | | $ | 3.41 | | | $ | 3.27 | |
Costless Collar - Henry Hub | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 48,663 | | | | - | | | | 10,000 | | | | - | | | | - | | | | - | | | | - | |
Average Put Price ($/Bbl) | | $ | 3.03 | | | $ | - | | | $ | 3.50 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
Average Call Price ($/Bbl) | | $ | 7.35 | | | $ | - | | | $ | 5.15 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (MMBtu/d) | | | 136,023 | | | | 120,838 | | | | 109,514 | | | | 69,070 | | | | 61,056 | | | | 50,962 | | | | 47,714 | |
Average Price ($/MMBtu) | | $ | 4.05 | | | $ | 3.90 | | | $ | 3.89 | | | $ | 3.76 | | | $ | 3.63 | | | $ | 3.41 | | | $ | 3.27 | |
| NGL Positions | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Price Swaps | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 11,264 | | | | 9,011 | | | | 6,427 | | | | - | | | | - | | | | - | | | | - | |
| Average Price ($/Bbl) | | $ | 0.96 | | | $ | 0.88 | | | $ | 0.83 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Volume (Bbl/d) | | | 11,264 | | | | 9,011 | | | | 6,427 | | | | - | | | | - | | | | - | | | | - | |
| Average Price ($/Bbl) | | $ | 0.96 | | | $ | 0.88 | | | $ | 0.83 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Fixed Gas Basis Swap | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Volume (Bbl/d)
| | | 97,148
| | | | 84,068
| | | | 77,423
| | | | -
| | | | -
| | | | -
| | | | -
| |
| Average Price ($/MMBtu) | | $ | (0.17) |
| | $ | (0.26) |
| | $ | (0.22) |
| | $ | - | | | $ | - | | | $ | - | | | $ | - | |
Balance Sheet Presentation
The following table summarizes the fair value of the derivatives outstanding on a gross and net basis:
| | | | |
| Balance sheet location, thousands of dollars | | Oil Commodity Derivatives | | | Natural Gas Commodity Derivatives | | | NGL Commodity Derivatives | | | Commodity Derivatives Netting (a) | | | Total Financial Instruments | |
| |
| |
| Assets | | | | | | | | | | | | | | | |
| Current assets - derivative instruments | | $ | 7,539 | | | $ | 39,124 | | | $ | 18,958 | | | $ | (19,118 | ) | | $ | 46,503 | |
| Other long-term assets - derivative instruments | | | 30,451 | | | | 39,797 | | | | 23,686 | | | | (45,917 | ) | | | 48,018 | |
| Total assets | | | 37,990 | | | | 78,921 | | | | 42,645 | | | | (65,035 | ) | | | 94,521 | |
| Liabilities | | | | | | | | | | | | | | | | | | | | |
| Current liabilities - derivative instruments | | | (2,897 | ) | | | (1,931 | ) | | | (14,388 | ) | | | 19,118 | | | | (98 | ) |
| Long-term liabilities - derivative instruments | | | (24 | ) | | | (29,261 | ) | | | (20,625 | ) | | | 45,917 | | | | (3,994 | ) |
| Total liabilities | | | (2,921 | ) | | | (31,193 | ) | | | (35,013 | ) | | | 65,035 | | | | (4,092 | ) |
| Net assets | | $ | 35,069 | | | $ | 47,728 | | | $ | 7,632 | | | $ | - | | | $ | 90,429 | |
| | | | |
| Balance sheet location, thousands of dollars | | Oil Commodity Derivatives | | | Natural Gas Commodity Derivatives | | | NGL Commodity Derivatives | | | Commodity Derivatives Netting (a) | | | Total Financial Instruments | |
| Current assets - derivative instruments | | $ | 5,411 | | | $ | 4,260 | | | $ | 3,893 | | | $ | (12,513 | ) | | $ | 1,051 | |
Other long-term assets - derivative instruments | | | 9,478 | | | | 6,300 | | | | 3,699 | | | | (15,123 | ) | | | 4,354 | |
| Total assets | | | 14,890 | | | | 10,560 | | | | 7,592 | | | | (27,636 | ) | | | 5,405 | |
| Liabilities | | | | | | | | | | | | | | | | | | | | |
Current liabilities - derivative instruments | | | (38,228 | ) | | | (44,236 | ) | | | (29,352 | ) | | | 12,513 | | | | (99,302 | ) |
Long-term liabilities - derivative instruments | | | (9,367 | ) | | | (11,561 | ) | | | (2,525 | ) | | | 15,123 | | | | (8,330 | ) |
Total liabilities | | | (47,594 | ) | | | (55,797 | ) | | | (31,877 | ) | | | 27,636 | | | | (107,632 | ) |
Net liabilities | | $ | (32,705 | ) | | $ | (45,238 | ) | | $ | (24,285 | ) | | $ | - | | | $ | (102,227 | ) |
(a) | Represents counterparty netting under our ISDA Agreements. See Note 2 – Summary of Significant Accounting Policies. For our derivative contracts, we may enter into master netting, collateral and offset agreements with counterparties. These agreements provide us the ability to offset a counterparty’s rights and obligations, request additional collateral when necessary, or liquidate the collateral in the event of counterparty default. We net the fair value of cash collateral paid or received against fair value amounts recognized for net derivative positions executed with the same counterparty under the same master netting or offset agreement. |
The following table summarizes the unrealized gains/losses on commodity derivatives, which are included in the (loss) gain on commodity derivative instruments line of the income statement:
| (in thousands of dollars) | | Oil Commodity Derivatives | | | Natural Gas Commodity Derivatives | | | NGL Commodity Derivatives | | | Total Financial Instruments | |
| |
| |
| Twelve Months Ended December 31, 2023 | | $ | 67,774 | | | $ | 92,966 | | | $ | 31,916 | | | $ | 192,656 | |
| Twelve Months Ended December 31, 2022 | | | 29,114 | | | | 21,198 | | | | 58,403 | | | | 108,715 | |
The following table summarizes the realized gains/losses on commodity derivatives, which are included in the “(loss) gain on commodity derivative instruments” line of the income statement:
| (in thousands of dollars) | | Oil Commodity Derivatives | | | Natural Gas Commodity Derivatives | | | NGL Commodity Derivatives | | | Total Financial Instruments | |
| |
| |
| Twelve Months Ended December 31, 2023 | | $ | (35,072 | ) | | $ | 7,646 | | | $ | (19,296 | ) | | $ | (46,722 | ) |
| Twelve Months Ended December 31, 2022 | | | (124,698 | ) | | | (175,443 | ) | | | (70,658 | ) | | | (370,798 | ) |
Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We measure certain assets and liabilities at fair value, using the fair value hierarchy noted below. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third-party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements. The fair value hierarchy gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs are described further as follows:
| Level 1 | Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. |
| Level 2 | Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over the counter (“OTC”) commodity derivative contracts in our portfolio to be Level 2. |
| Level 3 | Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. We consider our liability-classified long term incentive plan awards and put option liability to be Level 3 liabilities. See Note 13 – Equity and Note 14 – Compensation for additional details. |
Our assessment of the significance of an input to its fair value measurement requires judgment and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels.
Commodity Derivative Instruments
Our commodity derivative instruments include oil, natural gas and NGL swaps and collars. The fair value of our commodity derivative instruments is based on upon a third-party preparer’s calculation using mark-to-market valuation reports provided by our counterparties for monthly settlement purposes to determine the valuation of our derivative instruments. We do not have access to the specific proprietary valuation models or inputs used by our counterparties or third-party preparer.
We compare the third-party preparer’s valuation to counterparty valuation statements and investigate any significant differences. Additionally, we analyze monthly valuation changes in relation to movements in crude oil and natural gas forward price curves. The fair values reflect nonperformance risk inherent in the transaction using current credit default swap values for each counterparty for asset positions and the Company’s creditworthiness for liability positions. Accordingly, we recorded an adjustment to the fair value of our net derivative liability of $4.5 million and $2.4 million at December 31, 2023 and December 31, 2022, respectively.
Fair Value – Recurring Measurement Basis
The following table presents our financial assets and liabilities that were accounted for at fair value on a recurring basis on our consolidated balance sheets at December 31, 2023 and 2022 by level within the fair value hierarchy.
| | | December 31, 2023 | |
| (in thousands of dollars) | | Level 1 | | Level 2 | | Level 3 | | | Total | |
| Assets | | | | | | | | | | |
| Oil derivative instruments | | | | | | | | | | |
| Oil swaps | | $ | - | | $ | 32,728 | | $ | - | | | $ | 32,728 | |
| Oil collars | | | - | | | 2,341 | | | - | | | | 2,341 | |
| Natural gas derivative instruments | | | | | | | | | | | | | | |
| Natural gas swaps | | | - | | | 34,051 | | | - | | | | 34,051 | |
| Natural gas collars | | | - | | | 13,677 | | | - | | | | 13,677 | |
| NGL derivative instruments | | | | | | | | | | | | | | |
| NGL swaps | | | - | | | 7,632 | | | - | | | | 7,632 | |
| Net assets | | $ | - | | $ | 90,429 | | $ | - | | | $ | 90,429 | |
| | | |
(in thousands of dollars) |
| Level 1 | | Level 2 | | Level 3 | | | Total | |
| Assets | | | | | | | | | | |
Oil derivative instruments | | | | | | | | | | |
| Oil swaps | | $ | - | | $ | (33,991 | ) | $ | - | | | $ | (33,991 | ) |
| Oil collars | | | - | | | 1,286 | | | - | | | | 1,286 | |
Natural gas derivative instruments | | | | | | | | | | | | | | |
Natural gas swaps | | | - | | | (44,085 | ) | | - | | | | (44,085 | ) |
| Natural gas collars | | | - | | | (1,153 | ) | | - | | | | (1,153 | ) |
| NGL derivative instruments | | | | | | | | | | | | | | |
| NGL swaps | | | - | | | (24,284 | ) | | - | | | | (24,284 | ) |
| Net liabilities | | $ | - | | $ | (102,227 | ) | $ | - | | | $ | (102,227 | ) |
Fair Value – Nonrecurring Measurement Basis
Acquisitions and impairment of proved and unproved properties and other non-oil and natural gas properties are also measured at fair value on a nonrecurring basis. The Company utilizes a discounted cash flow model to estimate the fair value of property as of the measurement date which utilizes the following inputs to estimate future net cash flows: (i) estimated quantities of oil and condensate, natural gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) estimated production rates, future operating and development costs, which are based on the Company’s historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage.
We primarily have lease agreements for office buildings and vehicles. Our leases generally have lease terms of one year to four years, some of which may include options to extend or shorten the term of the lease at the Company’s discretion. We determine if an arrangement is a lease at inception. Some of our leases include lease and non-lease components. We have elected the practical expedient to not separate lease and non-lease components and account for both as a single lease component.
Operating lease right-of-use assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. For leases where the implicit rate is not determinable, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. For leases including options to extend or terminate the lease, we factor such terms into our determination of the present value of future payments when it is reasonably certain that we will exercise that option. Operating lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. Variable lease payments and short-term lease payments (leases with initial terms less than 12 months) are expensed as incurred.
Operating lease assets and liabilities are included in operating lease right-of-use assets, operating lease liabilities – current, and operating lease liabilities – noncurrent on our consolidated balance sheets. Our finance lease assets and liabilities are included in other property, plant, and equipment, current portion of long-term debt, and long-term debt on our consolidated balance sheets.
| | | December 31, | |
| (in thousands of dollars) | | 2023 | | | 2022 | |
| Operating leases | | | | | | |
Operating lease right-of-use assets | | $ | 12,362 | | | $ | 5,136 | |
Operating lease obligations - current | | | 841 | | | | 3,606 | |
Operating lease obligations - noncurrent | | | 25,316 | | | | 2,112 | |
Finance leases | | | | | | | | |
Other property, plant, and equipment (1) | | $ | 3,455 | | | $ | 3,084 | |
Current portion of long-term debt | | | 1,166 | | | | 717 | |
Long-term debt | | | 2,389 | | | | 1,920 | |
(1). | Finance lease assets are recorded net of accumulated amortization of $1.5 million and $0.4 million at December 31, 2023 and 2022, respectively. |
The following table summarizes the components of leases cost for the periods presented:
| | | Year Ended December 31, | |
| (in thousands of dollars) | | 2023 | | | 2022 | |
| Operating lease cost | | $ | 5,206 | | | $ | 5,357 | |
| Short-term lease cost | | | 18,105 | | | | 7,406 | |
| Finance lease cost | | | | | | | | |
| Amortization of right-of-use assets | | | 1,003 | | | | 388 | |
| Interest on lease liabilities | | | 198 | | | | 84 | |
| Total lease cost | | $ | 24,513 | | | $ | 13,235 | |
The following table summarizes the lease terms and discount rates:
| | | Year Ended December 31, | |
| | | 2023 | | | 2022 | |
| Lease term and discount rate | | | | | | |
| Weighted-average term (years) | | | | | | |
| Operating leases | | | 10.23 | | | | 1.80 | |
| Finance leases | | | 2.85 | | | | 3.50 | |
| Weighted-average discount rate (percent) | | | | | | | | |
| Operating leases | | | 7.43 | % | | | 6.20 | % |
| Finance leases | | | 5.86 | % | | | 5.70 | % |
The following table summarizes other lease information for the periods presented:
| | | Year Ended December 31, | |
| (in thousands of dollars) | | 2023 | | | 2022 | |
Cash paid for amounts included in the | | | | | | |
measurement of lease liabilities | | | | | | |
Operating cash flow from operating leases | | $ | 8,007 | | | $ | (4,633 | ) |
Operating cash flow from finance leases | | | (1,003 | ) | | | (375 | ) |
Financing cash flows from finance leases | | | (198 | ) | | | (82 | ) |
Future minimum lease payments under noncancellable leases as of December 31, 2023 were as follows:
| (in thousands of dollars) | | Operating Leases | | | Finance Leases | |
| 2024 | | $ | 1,607 | | | | 1,368 | |
| 2025 | | | 4,097 | | | | 1,363 | |
| 2026 | | | 3,951 | | | | 918 | |
| 2027 | | | 3,486 | | | | 175 | |
| 2028 | | | 3,527 | | | | - | |
| Thereafter | | | 22,736 | | | | - | |
| Total lease payments | | | 39,404 | | | | 3,825 | |
| Less: Portion representing imputed interest | | | (13,247 | ) | | | (270 | ) |
| Total lease liabilities | | | 26,157 | | | | 3,555 | |
| Less: Current portion of lease liabilities | | | (841 | ) | | | (1,166 | ) |
| Long-term lease liabilities | | $ | 25,316 | | | $ | 2,389 | |
| 7. | Long-Lived Assets and Impairment |
Our long-lived assets are comprised of oil and natural gas properties and other property, plant and equipment for the periods presented:
| (in thousands of dollars) | | 2023 | | | 2022 | |
Proved oil and natural gas properties(1) | | $ | 2,548,263 | | | $ | 2,310,497 | |
Unproved oil and natural gas properties | | | 126,557 | | | | 116,175 | |
Total oil and natural gas properties | | | 2,674,820 | | | | 2,426,672 | |
Other property, plant and equipment | | | 110,888 | | | | 77,230 | |
Less: Accumulated depletion, depreciation and amortization | | | (1,097,788 | ) | | | (876,451 | ) |
| Net property, plant and equipment | | $ | 1,687,920 | | | $ | 1,627,451 | |
(1). | Estimates of future asset retirement costs of $260.4 million and $249.1 million are included in our proved oil and natural gas properties at December 31, 2023 and 2022, respectively. |
Costs are excluded from the amortization base until proved reserves are established or impairment is determined.
Long-Lived Assets Impairment
During the year ended December 31, 2023, we recorded impairment losses totaling $66.8 million in proved properties. We incurred $3.5 million and $59.2 million of impairment in the first and second quarters of 2023 due to a significant decrease in commodity prices driven by a decrease in gas futures. We incurred $0.0 million and $4.1 million of impairment in the third and fourth quarters of 2023 due to significant downward revisions in reserves to certain impairment fields, driven by increased costs and decreased production. During the year ended December 31, 2022, we recorded impairment losses totaling $118.8 million in proved properties. We incurred $12 million of impairment in the second quarter of 2022 on divested properties as mentioned in Note 4 – Acquisitions and Divestitures, due to the sales price of the assets sold being lower than the net book value. We incurred $107.0 million of impairment in the fourth quarter of 2022 due to an increase in operating costs caused by supply chain pressures and an inflationary environment as well as changes in capital plans due to 2022 acquisitions.
Additionally, as a result of expiring leases and our periodic assessment of unproved properties, we amortized $0.0 million and $0.1 million of unproved oil and natural gas properties and reported amounts as depletion, depreciation and amortization in our consolidated statement of operations for the periods ended December 31, 2023 and 2022, respectively.
Other long-term assets consist of the following:
| (in thousands of dollars) | | 2023 | | | 2022 | |
| Property reclamation | | $ | 11,910 | | | $ | 11,359 | |
Unamortized debt issuance costs | | | 13,206 | | | | 17,920 | |
| Security deposits | | | 1,735 | | | | 2,904 | |
| Other | | | 8,726 | | | | 6,266 | |
| Total other long-term assets | | $ | 35,577 | | | $ | 38,449 | |
Net Profit Interest
We have a net profit interest (“NPI”) related to the Jay Field. The NPI is held 50% by Maverick and a third party (“NPI Holder”). Under the arrangement, the NPI is payable after: (i) funds are withheld, to the extent allowable each month under the arrangement, to pay for the NPI holder’s share of future development costs and abandonment obligations, and (ii) we are reimbursed for the NPI holder’s share of excess historical production costs. Once the NPI holder’s share of the excess historical costs is reimbursed, the NPI will be payable monthly to the extent the NPI for that month exceeds the amount withheld for that month for future development costs and abandonment obligations. The NPI holder’s share of excess historical production costs amounted to $11.5 million and $15.4 million at December 31, 2023 and 2022, respectively.
Additionally, we will retain the NPI holder’s share of future development costs and abandonment obligations, subject to future production, production costs, and capital spending level, which will be paid using the funds withheld. The NPI holder’s share along with our share of the abandonment costs as of December 31, 2023 and 2022 are reflected in asset retirement obligations on the consolidated balance sheets. Under the arrangement, we have the option to deposit into a separate account the funds withheld from the NPI holder for their portion of the future development costs and abandonment obligations. At December 31, 2023 and 2022, the funds totaled $0.0 million and $13.6 million, respectively, and are reflected in long-term restricted cash on our consolidated balance sheets. See additional details regarding the Jay Field NPI in Note 12 – Commitments and Contingencies and Note 16 – Subsequent Events.
Property Reclamation Deposit
As of December 31, 2023 and 2022, we had a property reclamation deposit of $11.9 and $11.4 million, respectively, included in other long-term assets, held in an escrow account as security for future abandonment and remediation obligations for the Jay Field. We are required to maintain the escrow account in effect for three years after all abandonment and remediation obligations have been completed. The funds in the escrow account are not to be returned to us until the later of three years after satisfaction of all abandonment obligations or December 31, 2026. At certain dates subsequent to closing, we have the right to request a refund of a portion or all of the property reclamation deposit. The seller has the sole discretion to grant our refund request. In addition to the cash deposit, we are required to provide letters of credit. At December 31, 2023 and 2022, we had $21.0 million in letters of credit related to the property reclamation deposit.
| 9. | Accounts Payable and Accrued Expenses |
Accounts payable and accrued expenses consist of the following:
| (in thousands of dollars) | | 2023 | | | 2022 | |
| Accounts payable | | $ | 112,218 | | | $ | 175,804 | |
| Revenue and royalties payable | | | 93,315 | | | | 102,899 | |
Wages and salaries payable | | | 21,008 | | | | 13,134 | |
| Accrued interest payable | | | 12,100 | | | | 6,071 | |
Production and property taxes payable | | | 22,217 | | | | 26,808 | |
Hedge settlement payables | | | 8,911 | | | | 11,331 | |
| Other current liabilities | | | 2,868 | | | | 4,346 | |
| Total accounts payable and accrued expenses | | $ | 272,637 | | | $ | 340,393 | |
Our debt was comprised of the following:
(in thousands of dollars) | | 2023 | | | 2022 | |
| Credit Facility | | $ | 190,000 | | | $ | 410,000 | |
| ABS Notes | | | 640,000 | | | | - | |
| Finance Lease Obligations | | | 3,555 | | | | 2,637 | |
| Debt issuance costs | | | (12,377 | ) | | | - | |
| Notes held by ABS parent | | | (10,000 | ) | | | - | |
| Total debt | | | 811,178 | | | | 412,637 | |
| Current portion, long-term debt | | | (112,607 | ) | | | - | |
| Current portion of finance lease obligations | | | (1,166 | ) | | | (717 | ) |
| Total long-term debt | | $ | 697,405 | | | $ | 411,920 | |
ABS Notes
In connection with the ABS Financing Transaction (see Note 4 – Acquisitions and Divestitures), on October 26, 2023, ABS Issuer acquired certain oil and natural gas interests in currently-producing oil and natural gas wells and other assets from Unbridled pursuant to an asset purchase agreement and the acquisition was funded by the issuance of the ABS Notes (as defined in Note 4 – Acquisitions and Divestitures), due December 2038, pursuant to a note purchase agreement. At December 31, 2023, the ABS Notes were comprised of the following:
| (in thousands of dollars) | | 2023 | |
| Series 2023 | | | - 1 | | Class A-1 8.121% Notes | | $ | 285,000 | |
| Series 2023 | | | - 1 | | Class A-2 8.946% Notes | | | 260,000 | |
| Series 2023 | | | - 1 | | Class B 12.436% Notes | | | 95,000 | |
| Total ABS Notes | | | 640,000 | |
The ABS Notes are secured by certain oil and natural gas interests in currently producing oil and natural gas wells and other assets. The ABS Notes accrue interest at the respective stated per annum rates and have a final maturity date of December 15, 2038. Interest and principal payments are payable on a monthly basis. During the period ended December 31, 2023, we incurred $10.3 million of interest related to the ABS Notes.
The ABS Notes are subject to a series of covenants and restrictions customary for transactions of this type, including (i) that the Issuer maintains specified reserve accounts to be used to make required interest payments in respect of the ABS Notes, (ii) provisions relating to optional and mandatory prepayments and the related payment of specified amounts, including specified make-whole payments under certain circumstances, (iii) certain indemnification payments in the event, among other things, that the assets pledged as collateral are used in stated ways defective or ineffective, (iv) covenants related to recordkeeping, access to information and similar matters, and (v) the Issuer will comply with all laws and regulations which it is subject to. The ABS Notes are also subject to customary accelerated amortization events provided for in the indenture, including events tied to failure to maintain stated debt service coverage ratios, failure to maintain certain production metrics, certain change of control and management termination events, and event of default and the failure to repay or refinance the ABS Notes on the applicable scheduled maturity date. The ABS Notes are subject to certain customary events of default, including events relating to non-payment of required interest, principal, or other amounts due on or with respect to the ABS Notes, failure to comply with covenants within certain time frames, certain bankruptcy events, breaches of specified representations and warranties, failure of security interests to be effective and certain judgments.
Under the indenture, the Company must maintain the following financial covenants determined as of the last day of the quarter: 1) Aggregate Debt Service Coverage Ratio (DSCR) less than 1.05, 2) Senior DSCR less than 1.25
As of December 31, 2023, we were in compliance with our covenants under the ABS Notes.
Senior Secured Reserve-Based Credit Facility
In connection with the Permian Acquisition (see Note 4 - Acquisitions and Divestitures), on January 27, 2022, we entered into an agreement with a syndicate of banks including JPMorgan Chase Bank acting as Administrator, Royal Bank of Canada, Citizens Bank, KeyBank National Association acting as co‑syndication agents, RBC Capital Markets, and KeyBank Capital Markets (the “Credit Facility”). The agreement is for a maximum $1 billion credit facility with an initial $500 million borrowing base. The maturity date is April 1, 2026. The Credit Facility replaced the Credit Agreement (defined below) subsequent to its closing on April 1, 2022, incurring deferred financing costs of $16.3 million.
The Credit Facility limits the amounts we could borrow to a borrowing base amount determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria. Our obligations under the credit facility were collateralized by substantially all of our oil and natural gas properties, including mortgage liens on oil and natural gas properties having at least 85% of the reserve value as determined by reserve reports.
The Credit Facility contains certain customary affirmative and negative covenants, including financial covenants requiring maintenance of the Consolidated Total Debt to EBITDAX Ratio to be less than 3.00 to 1.00 and a Current Ratio of no less than 1.00 to 1.00.
At our election, borrowings under the credit facility may be made on an Alternate Base Rate (“ABR”) or a Secured Overnight Financing Rate (“SOFR”) basis plus an applicable margin. In connection with the Credit Facility, the applicable margins vary from 2.00% to 3.00% for ABR borrowings and 3.00% to 4.00% for SOFR borrowings depending on the borrowing base. In addition, we are also required to pay a commitment fee on the amount of any unused commitments at a rate of 0.50% per annum. Interest on ABR borrowings and the commitment fee are generally payable quarterly. As of December 31, 2023, the effective interest rate of the Credit Facility was 9.24%.
In June 2022, we entered into an amendment to the Credit Facility (the “First Amendment”) which increased the borrowing base from the initial $500 million to $750 million. Each lender’s borrowing capacity was increased with the exception of Goldman Sachs Bank, and we accounted for the First Amendment as a modification of debt. We incurred deferred financing costs of $2.6 million in relation to this amendment.
In October 2022, we entered into the second amendment to the Credit Facility (the “Second Amendment”), which increased the borrowing base to $1 billion. Each lender’s borrowing capacity was increased with the exception of Texas Capital Bank, and we accounted for the Second Amendment as a modification of debt. We incurred deferred financing costs of $2.6 million in relation to this amendment.
In July 2023, we entered into the third amendment to the Credit Facility (the “Third Amendment”), which reduced the borrowing base from $1 billion to $750 million. Each lender’s borrowing capacity was decreased, and we accounted for the Third Amendment as a modification of debt. Additionally, the Third Amendment allowed for a one-time cash distribution to our equity holders not to exceed $10 million in aggregate through September 30, 2023. We did not incur deferred financing costs in relation to the Third Amendment.
In October 2023 in conjunction with the ABS Financing Transaction, we entered into the fourth amendment to the Credit Facility (the “Fourth Amendment”), which amended in its entirety the original Credit Facility. Pursuant to the Fourth Amendment, among other things, the borrowing base was reduced from $750 million to $350 million, and the respective reduced commitments of the various lending banks were reallocated among the continuing lenders to assign the exiting lenders’ commitment. We accounted for the decreases in a lender’s borrowing capacity as a modification and accounted for any lender that exited the credit facility as a debt extinguishment. In connection with ABS, we repaid $0.0 million as of December 31, 2023.
We incurred deferred financing costs of $5.6 million in relation to the Fourth Amendment. At December 31, 2023, our borrowing base is $350.0 million, and the aggregate commitment of all lenders is $1 billion. Our next borrowing base redetermination is scheduled for April 1, 2024.
Unamortized debt issuance costs associated with the Credit Facility were $13.2 million as of December 31, 2023.
As of December 31, 2023, we were in compliance with our debt covenants under the Credit Facility.
Credit Agreement
On October 24, 2018, BOLP, as borrower, entered into a $1.0 billion credit agreement with Maverick Natural Resources, LLC as the parent guarantor, JPMorgan Chase Bank, N.A., as the administrative agent, collateral agent and letter of credit issuer, Royal Bank of Canada, as syndication agent and other syndicate financial institutions (the “Lenders”) (the “Credit Agreement”). The Credit Agreement had a maturity date of October 24, 2023, and was replaced by the Credit Facility (discussed above) effective April 1, 2022.
Interest Expense
Our interest expense is as follows:
| (in thousands of dollars) | | 2023 | | | 2022 | |
Credit Facility (a) | | $ | 40,828 | | | $ | 18,566 | |
ABS Notes (b) | | | 10,307 | | | | - | |
Amortization of deferred debt issuance costs, Credit Facility | | | 10,274 | | | | 6,462 | |
Amortization of deferred debt issuance costs, ABS Notes | | | 581 | | | | - | |
Other Credit Facility, net | | | 186 | | | | 81 | |
| | $ | 62,176 | | | $ | 25,109 | |
(a) Includes commitment fees and other fees | | $ | |
| | $ | | |
(b) Includes commitment fees and other fees | | $ | - | | | $ | - | |
| 11. | Asset Retirement Obligations |
We recognize the fair value of a liability for an ARO in the period it is incurred if a reasonable estimate of fair value can be made. Our ARO represents the present value of the expected costs to plug, abandon and remediate producing and shut-in wells at the end of the productive lives in compliance with applicable local, state and federal laws and applicable lease terms. We estimate the value of our ARO by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The ARO liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and natural gas properties using the unit-of-production method. We review our ARO estimates and assumptions periodically and, to the extent future revisions to these assumptions impact the fair value of the existing ARO liability, we make a corresponding adjustment to the related asset. We consider these inputs to be Level 3 inputs as discussed in Note 2 – Summary of Significant Accounting Policies and Note 5 – Financial Instruments and Fair Value Measurements.
The following table presents the balance and activity in our ARO for the periods presented:
| (in thousands of dollars) | | 2023 | | | 2022 | |
| Asset retirement obligations, beginning of year | | $ | 253,281 | | | $ | 225,817 | |
| Liabilities incurred from drilling | | | - | | | | 769 | |
| Liabilities settled | | | (19,839 | ) | | | (7,335 | ) |
Liabilities related to divested properties(1) | | | (9,970 | ) | | | (6,345 | ) |
Liabilities related to acquired properties(2) | | | - | | | | 22,916 | |
Revisions of estimates(3) | | | 11,535 | | | | 3,036 | |
Accretion expense(4) | | | 14,666 | | | | 14,425 | |
| Asset retirement obligations end of year | | | 249,673 | | | | 253,281 | |
| Less: Current portion of asset retirement obligations | | | (7,282 | ) | | | (5,060 | ) |
Noncurrent portion of asset retirement obligations | | $ | 242,391 | | | $ | 248,221 | |
| | (1). | Includes ARO related to various sold properties. See Note 4 – Acquisitions and Divestitures. |
| | (2). | Related to ARO acquired from Permian and Anadarko acquisitions. See Note 4 – Acquisitions and Divestitures. |
| | (3). | During the periods presented, we revised our estimates primarily to reflect the following changes in estimated well lives, oil and natural gas prices and plugging and abandonment cost estimates. |
| | (4). | Included in DD&A on our consolidated statements of operations. |
| 12. | Commitments and Contingencies |
Surety Bonds and Letters of Credit
In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily relate to abandonments, environmental and other responsibilities where governmental and other organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At both December 31, 2023 and 2022, we had $21.3 million of irrevocable letters of credit outstanding, of which $21.0 million related to the property reclamation deposit as discussed in Note 8 – Other Long-Term Assets. At December 31, 2023, no amounts were drawn under the letters of credit.
Legal Proceedings
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings, other than litigation in regards to the Jay Field NPI. As of December 31, 2023, we had accrued $4.2 million related to this litigation. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject.
Common Units
During 2023, we repurchased 3,222 units for $1.5 million for certain members and executives.
Member Distributions
In October 2022, the Board approved a distribution of totaling $120 million at $41.43 per common unit to the common unitholders of record on the applicable record date.
In January 2023, the Board approved a distribution of $30 million at $10.36 per common unit to the common unitholders of record on the applicable record date.
In May 2023, the Board approved two distributions totaling $50 million. The first distribution was $30 million at 10.36 per common unit to the common unitholders of record on the applicable record date. The second distribution was $20 million at $6.91 per common unit to the common unitholders of record on the applicable record date.
In October 2023, the Board approved a distribution of $260 million at $89.76 per common unit to the common unitholders of record on the applicable record date.
The state of Oklahoma requires operators to withhold 5% of all production revenues associated with royalty interests held by Oklahoma nonresidents to be offset against state income taxes. As Maverick is not subject to income taxes as a limited liability company, the tax liability associated with the operations of Unbridled is the responsibility of the members. As such, the balance of Oklahoma state withholding has been reflected as an equity distribution. At December 31, 2023 and 2022, the total distributions attributable to Oklahoma state withholding is $0.6 million and $0.4 million, respectively.
Defined Contribution Plan
We sponsor a 401(k) defined contribution plan for eligible employees, and the Plan includes a provision for employer matching contributions. We recorded general and administrative expenses for our matching contributions totaling $2.4 million and $1.3 million for the years ended December 31, 2023 and 2022, respectively.
Long Term Incentive Plans
Maverick Natural Resources, LLC Long Term Incentive Plan (or the “LTIP”) was effective and approved by the Board in August 2019. The LTIP provides for the compensation of employees and eligible nonemployee directors of the Company and its subsidiaries by granting Incentive Units to employees and directors with 3-year and 1-year vesting terms, respectively, from the grant date. The Incentive Unit awards are accounted for as liability-classified awards that will settle in cash and reported as accounts payable and accrued expenses in our consolidated balance sheets. Forfeitures associated with the LTIP awards granted are recognized when they occur.
The Incentive Unit Amounts upon vesting are payable in cash and is equal to the quotient of the Implied Equity Value as of the last day of the fiscal year preceding the Vesting Event (provided, that, in the case of vesting due to an Exit Event or Asset Sale, the Implied Equity Value is, in the sole discretion of the Administrator, either (i) the Implied Equity Value as of the last day of the fiscal year preceding such Vesting Event, or (ii) the Implied Equity Value as of another appropriate date determined by the Administrator, divided by a fixed number subject to adjustment by the Administrator. The Implied Equity Value means an amount equal to the quotient of Adjusted EBITDA and Peer Multiple, less Net Debt, plus Cumulative Distributions. The value of each LTIP unit at December 31, 2023 was estimated at $78.34 per unit. The fair value measurement is based on significant inputs not observable in the market and thus represents a Level 3 measurement within the fair value hierarchy.
In August 2023, the Company granted long-term incentive awards to various executives in the form of cash. The Awards are subject to time-based vesting conditions.
The following table summarizes liability-classified performance unit activity for the years ended December 31, 2023 and 2022 and provides information for unvested units as of December 31, 2023 and 2022:
| | | Number of Units | |
| Unvested units at December 31, 2021 | | | 95,814 | |
| Granted | | | 88,524 | |
| Forfeited | | | (30,305 | ) |
| Vested | | | (57,909 | ) |
| Unvested units at December 31, 2022 | | | 96,124 | |
| Granted | | | 108,473 | |
| Forfeited | | | (20,068 | ) |
| Vested | | | (64,194 | ) |
| Unvested units at December 31, 2023 | | | 120,335 | |
The Company recognized cash-based long-term incentive compensation of $1.3 million and $1.0 million for executive awards in general and administrative expense in our consolidated statement of operations for both the years ended December 31, 2023 and 2022.
Equity Incentive Awards
For equity classified awards, we recognize expense for the grant date fair value of the award over the vesting period of the awards. Forfeitures are accounted for as they occur. The grant date fair value of the common units was derived from an estimate of Enterprise Value, or the fair value of our upstream and midstream businesses and long-term debt and liabilities. Significant inputs used to determine the fair values of properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by our management at the time of the valuation and are sensitive and subject to change.
In August 2023, the Company granted executive incentive awards to various executives in the form of common units. The Awards are subject to performance-based vesting conditions based on market conditions. The expected term for awards granted in 2023 is 1.4 to 2.4 years. The Company did not grant any awards in 2022.
The Company recognized non-cash unit-based compensation of $1.6 million in general and administrative expense in our consolidated statement of operations for the year ended December 31, 2023. The weighted average grant date fair value for the award was $309.13 per common unit. As of December 31, 2023, 28,900 common units have been granted, 16,895 common units remain unvested, and unamortized compensation expense is $4.9 million over the next four years.
The Company recognized non-cash unit-based compensation of $1.2 million in general and administrative expense in our consolidated statement of operations for the year ended December 31, 2022. The weighted average grant date fair value for the award was $333.16 per common unit. As of December 31, 2022, 17,222 common units have been granted, 8,663 common units remain unvested, and unamortized compensation expense is $3.2 million over the next four years.
In 2023 and 2022, as part of the Company’s restructuring plan, we incurred restructuring costs of approximately $1.6 million and $0.3 million, respectively, primarily related to plans for reductions in workforce to improve operational efficiencies.
Restructuring costs recorded in our consolidated statements of operations are presented for the respective periods:
| (in thousands of dollars) | | 2023 | | | 2022 | |
| Type of restructuring cost | | | | | | |
| Severance and related benefit costs | | $ | 1,485 | | | $ | 120 | |
| Office-lease abandonment and relocation | | | 146 | | | | 163 | |
| | | $ | 1,631 | | | $ | 283 | |
The Company has evaluated subsequent events through April 29, 2024, the date the financial statements were issued and noted the events below.
In February 2024, the Company replaced the performance-based equity incentive awards granted in August 2023 with time-based equity incentive awards.
In March 2024, the Company settled its Jay Field litigation for $9.2 million. As part of the settlement, the Company purchased the net profit interest in the Jay Field for approximately $5 million. The Company recognized a litigation settlement accrual as of December 31, 2023 for $4.2 million.
Unaudited Supplementary Information.
Oil and Gas Exploration and Production Activities
The Company has only one reportable operating segment, which is oil and gas development, exploration and production in the U.S. See the Company’s accompanying consolidated statements of operations for information about results of operations for oil and gas producing activities.
Capitalized Costs
| (in thousands of dollars) | | At December 31, | |
| Category | | 2023 | | | 2022 | |
Proved properties and related producing assets | | $ | 2,518,413 | | | $ | 2,295,001 | |
Warehouse Inventory | |
| 29,850 | | |
| 15,496 | |
Unproved properties | |
| 126,557 | | |
| 116,175 | |
Accumulated depreciation, depletion and amortization | |
| (1,053,454 | ) | |
| (843,848 | ) |
| Net Capitalized Costs | | $ | 1,621,366 | | | $ | 1,582,824 | |
Costs Incurred for Oil and Gas Producing Activities
| (thousands of dollars) | | Year Ended December 31, | |
| | 2023 | | | 2022 | |
| Property Acquisition Costs | | | | | | |
| Proved | | $
| 3,529 | | | $ | 514,488 | |
| Unproved | |
| 14,608 | | |
| 27,274 | |
| Exploration Costs | |
| 160 | | |
| 1,213 | |
| Development Costs (a) | |
| 259,365 | | |
| 292,910 | |
| Total Costs Incurred | | $ | 277,662 | | | $ | 835,885 | |
| a. | Development costs incurred for oil and gas producing activities includes the following amounts: |
| (thousands of dollars) | | Year Ended December 31, | |
| | 2023 | | | 2022 | |
Development Drilling | | $ | 185,744 | | | $ | 241,452 | |
Production Facilities and Equipment Upgrades | |
| 35,571 | | |
| 34,584 | |
Warehouse Inventory | |
| 14,354 | | |
| 2,450 | |
Capitalized G&A | |
| 12,078 | | |
| 10,599 | |
Asset Retirement Obligations | |
| 11,615 | | |
| 3,805 | |
Other | |
| 2 | | |
| 20 | |
| Total Development Costs Incurred | | $ | 259,364 | | | $ | 292,910 | |
Results of Operations from Natural Gas and Oil Producing Activities
The table below sets forth the results of operations from natural gas and oil producing activities:
| (in thousands of dollars) | | 2023 | | | 2022 | |
Sales | | $ | 896,493 | | | $ | 1,343,817 | |
Realized (loss) gain on commodity derivatives | | | (46,722 | ) | | | (370,798 | ) |
Lease Operating Expenses | | | (388,237 | ) | | | (449,652 | ) |
Depreciation, depletion and amortization | | | (157,837 | ) | | | (126,623 | ) |
Impairment of oil and natural gas properties | | | (66,785 | ) | | | (118,839 | ) |
Results of operations | | $ | 236,912 | | | $ | 277,905 | |
The results of operations shown above exclude general and administrative.
Reserve Quantity Information
The estimates of the Company’s proved reserves as of December 31, 2023 and December 31, 2022 were based on evaluations prepared by independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions based upon an average of the first-day-of-the-month commodity price during the 12-month period ending on the balance sheet date with no provision for price and cost escalations except by contractual arrangements.
Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling and production performance may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
The following table provides a roll forward of total proved reserves.
(Thousands of dollars)
| | Total (MBoe) | | | Oil (MBbl) | | | NGL (MBoe) | | | Gas (MMcf) | |
| Proved reserves | | | | | | | | | | | | |
| Beginning balance, 12/31/2021 | | | 304,570 | | | | 83,476 | | | | 64,218 | | | | 941,258 | |
| Revision of previous estimates | | | 30,538 | | | | 2,932 | | | | 22,430 |
| | | 31,058 | |
| Extensions, discoveries and other additions | | | 18,427
| | | | 6,020
| | | | 4,467
| | | | 47,639
| |
| Purchase of reserves in-place | | | 58,626 | | | | 27,895 | | | | 5,554 | | | | 151,060 | |
| Sale of reserves in-place | | | (5,595 | ) | | | (2,502 | ) | | | (814 | ) | | | (13,673 | ) |
| Production | | | (25,297 | ) | | | (7,767 | ) | | | (5,892 | ) | | | (69,829 | ) |
| Ending balance, 12/31/2022 | | | 381,268 | | | | 110,054 | | | | 89,963
| | | | 1,087,513 | |
| Revision of previous estimates | | | (76,129 | ) | | | (11,841 | ) | | | (16,851 | ) | | | (284,625
| ) |
| Extensions, discoveries and other additions | | | 9,633 | | | | 4,762
| | | | 578
| | | | 25,759 | |
| Sale of reserves in-place | | | (3,059 | ) | | | (762
| ) | | | (778 | ) | | | (9,119 | ) |
| Production | | | (24,959 | ) | | | (8,257 | ) | | | (5,714 | ) | | | (65,929 | ) |
| Ending balance, 12/31/2023 | | | 286,755 | | | | 93,957
| | | | 67,198 | | | | 753,600 | |
Proved developed reserves
| | |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Ending balance, 12/31/2021
| | | 254,618
|
|
|
| 66,002
|
|
|
| 55,288
|
|
|
| 799,965
| |
| Ending balance, 12/31/2022 | | | 304,331
|
|
|
| 86,403
|
|
|
| 72,476
|
|
|
| 872,712
| |
| Ending balance, 12/31/2023 | | | 235,389
|
|
|
| 75,237
|
|
|
| 58,240
|
|
|
| 611,472
| |
Proved undeveloped reserves
| | |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Ending balance, 12/31/2021
| | | 49,953
|
|
|
| 17,474
|
|
|
| 8,930
|
|
|
| 141,293
| |
| Ending balance, 12/31/2022 | | | 76,937
|
|
|
| 23,650
|
|
|
| 17,487
|
|
|
| 214,801
| |
| Ending balance, 12/31/2023 | | | 51,366 | |
|
| 18,720
|
|
|
| 8,958
|
|
|
| 142,128
| |
| 1) | For the year ended December 31, 2023, the Company added 9.6 MMBOE through extensions primarily related to increased pricing and future drilling plans on proved undeveloped location in the Company’s Western Anadarko and Permian assets. These additions were offset by negative revisions of 76.1 MMBOE, reductions in production of 25.0 MMBOE, and the removal of 3.1 MMBOE related to the Divestiture of properties in Western Anadarko Basin, West Texas, and Wyoming. See Note 4 – Acquisitions, Assets Held for Sale, and Divestitures for further discussion. |
| 2) | For the year ended December 31, 2022, the Company added 58.6 MMBOE from acquisitions during the period related to the Permian Acquisition and the Anadarko Acquisition. See Note 4 – Acquisitions, Assets Held for Sale, and Divestitures for further discussion. The Company also added 30.5 MMBOE of estimated proved reserves through positive price and performance revisions, primarily driven by improved commodity prices during 2022. In addition, the Company added 18.4 MMBOE through extensions primarily related to increased pricing and future drilling plans on proved undeveloped location in the Company’s Western Anadarko assets. These additions were offset by production of 25.3 MMBOE and the removal of 5.6 MMBOE related to the Divestiture of properties in California and Michigan. See Note 4 – Acquisitions, Assets Held for Sale, and Divestitures for further discussion. |
The NYMEX prices used for oil and gas reserve preparation, based upon SEC guidelines, were as follows:
| | | Year Ended December 31, | | | % Change | |
| | | 2023 | | | 2022 | | | 2023 to 2022 | | | 2022 to 2021 | |
Oil per BBL | | $ | 78.21 | | | $ | 94.14 | | | | -17 | % | | | 41 | % |
Gas per MCF | | $ | 2.64 | | | $ | 6.36 | | | | -59 | % | | | 77 | % |
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is computed by applying commodity prices used in determining proved reserves (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved reserves less estimated future expenditures (based on year-end estimated costs) to be incurred in developing and producing the proved reserves, discounted using a rate of ten percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and gas properties plus available carryforwards and credits and applying the current tax rates to the difference. The discounted future cash flow estimates do not include the effects of the Company’s commodity derivative contracts.
Discounted future cash flow estimates, like those shown below, are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
The standardized measure of discounted future cash flows as well as a roll forward in total for each respective year are as follows:
| (in thousands of dollars) | | 2023 | | | 2022 | |
Future cash inflows (total revenues) | | $ | 10,082,939 | | | $ | 19,447,716 | |
Future production costs (severance and ad valorem taxes plus LOE) | | | (4,796,251 | ) | | | (7,255,342 | ) |
Future development costs (capital costs) | | | (1,707,946 | ) | | | (1,989,406 | ) |
Future income tax expense | | | (19,546 | ) | | | (41,120 | ) |
| Future net cash flows | | | 3,559,196 | | | | 10,161,848 | |
10% annual discount for estimated timing of cash flows | | | (1,548,849 | ) | | | (5,043,697 | ) |
| Standardized measure of DFNCF | | $ | 2,010,347 | | | $ | 5,118,151 | |
Changes in Standardized Measure of Discounted Future Net Cash Flows
| (in thousands of dollars) | | 2023 | | | 2022 | |
| | | | | | | |
| Beginning balance | | $ | 5,118,150 | | | $ | 2,654,919 | |
Net changes in prices and production costs | | | (2,300,636 | ) | | | 2,056,197 | |
Net change in future development costs | | | 12,714 | | | | (214,806 | ) |
Oil & gas net revenue | | | (511,575 | ) | | | (886,488 | ) |
Extensions | | | 109,046 | | | | 207,825
| |
Acquisition of reserves | | | - | | | | 628,906 | |
Disposition of reserves | | | (35,438
| )
| | | (28,777
| ) |
Revisions of previous quantity estimates | | | (997,147
| ) | | | 542,400 | |
Previously estimated development costs incurred | | | 70,396 | | | | 59,450 | |
Net change in taxes | | | 10,400 |
| | | (11,217 | ) |
Accretion of discount | | | 513,870
| | | | 257,161 | |
Changes in timing and other | | | 20,567 | | | | (147,420 | ) |
| Ending Balance | | $ | 2,010,347 | | | $ | 5,118,150 | |
