“Hydraulic fracturing.” The technique of improving a well’s production by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.
“Infill well.” A subsequent well drilled in an established spacing unit of an already established productive well in the spacing unit. Acreage on which infill wells are drilled is considered developed commencing with the initial productive well established in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.
“Net acres.” The percentage ownership of gross acres. Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).
“Net well.” A well that is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.
“NYMEX.” The New York Mercantile Exchange.
“OPEC.” The Organization of Petroleum Exporting Countries.
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“Recompletion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible crude oil, NGLs and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Service well.” A service well is drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“Stratigraphic test well.” A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
“Unconventional play.” An area believed to be capable of producing crude oil, NGLs, and/or natural gas occurring in cumulations that are regionally extensive but require recently developed technologies to achieve profitability. These areas tend to have low permeability and may be closely associated with source rock as this is the case with crude oil and natural gas shale, tight crude oil and natural gas sands and coal bed methane.
“Undeveloped acreage.” Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil, NGLs, and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage includes net acres held by operations until a productive well is established in the spacing unit.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Wellbore.” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.
“West Texas Intermediate or WTI.” A light, sweet blend of oil produced from the fields in West Texas.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own crude oil, NGLs, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
“Workover.” Operations on a producing well to restore or increase production.
Terms used to assign a present value to or to classify our reserves:
“Developed Oil and Gas Reserves.” Oil and natural gas reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
“Possible reserves.” The additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.
“Pre-tax PV-10%” or “PV-10.” The estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.
“Probable reserves.” The additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which together with proved reserves, are as likely as not to be recovered.
“Proved developed non-producing reserves (PDNPs).”Proved crude oil, NGLs, and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate, but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.
“Proved developed producing reserves (PDPs).” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional crude oil, NGLs, and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
“Proved reserves.” The quantities of crude oil, NGLs and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.
(i) The area of the reservoir considered as proved includes: (A) the area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil, NGLs or natural gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) the project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions.
“Proved undeveloped drilling location.” A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
“Proved undeveloped reserves” or“PUDs.” Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves will not be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir or an analogous reservoir.
“Reserves.” Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and allpermits and financing required to implement the project.
“Standardized measure.” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
“Undeveloped Oil and Gas Reserves.” Oil and natural gas reserves of any category that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Northern Oil and Gas, Inc. (the “Company,” “Northern,” “our” and words of similar import), a Delaware corporation, is an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties in the United States, primarily in the Williston Basin, the Permian Basin, the Appalachian Basin and, following the closing of the XCL Acquisition (as defined herein; see Note 3) in October 2024, the Uinta Basin. The Company’s common stock trades on the New York Stock Exchange under the symbol “NOG”.
The Company’s principal business is crude oil and natural gas exploration, development, and production with operations in the United States. The Company’s primary strategy is investing in non-operated minority working and mineral interests in oil and gas properties, with a core area of focus in premier basins within the United States.
NOTE 2 BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The financial information included herein is unaudited. The balance sheet as of December 31, 2023 has been derived from the Company’s audited financial statements for the year ended December 31, 2023. However, such information includes all adjustments (consisting of normal recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of the financial position, results of operations and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year.
Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”). The condensed financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2023, which were included in the Company’s 2023 Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
Out-of-Period Adjustments
During the three months ended September 30, 2024, the Company identified certain errors in its previously issued financial statements that have now been corrected through cumulative out-of-period adjustments in the condensed financial statements as of and for the three and nine months ended September 30, 2024. The errors relate, primarily, to improper classifications of income taxes withheld by the state of New Mexico, from January 2021 through June 2024, that were recorded as production tax expense. As a result, the Company recorded an out-of-period adjustment of approximately $32.1 million in the three months ended September 30, 2024 to record an income tax receivable, offset by a reduction in production taxes. Further, in the three months ended September 30, 2024, the Company recorded an out-of-period adjustment of approximately $6.7 million to income tax expense, offset by an increase in deferred tax liabilities. These errors understated net income for the fiscal years ended December 31, 2023, 2022, and 2021, by approximately $9.3 million, $11.2 million, and $0.5 million, respectively. Management considered qualitative and quantitative factors and concluded the out-of-period adjustments are immaterial to 2024 and each of the applicable periods.
Use of Estimates
The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The most significant estimates relate to proved crude oil and natural gas reserves, which includes limited control over future development plans as a non-operator, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, fair value of contingent consideration, acquisition date fair values of assets acquired and liabilities assumed, impairment of crude oil and natural gas properties, asset retirement obligations and deferred income taxes.
Management’s estimates and assumptions were based on historical data and consideration of future market conditions. Given the uncertainty inherent in any projection, actual results may differ from the estimates and assumptions used, and conditions may change, which could materially affect amounts reported in the unaudited condensed financial statements.
Adopted and Recently Issued Accounting Pronouncements
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.
In November 2023, the FASB issued ASU 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires the Company to expand the breadth and frequency of segment disclosures to include additional information about significant segment expenses, the chief operating decision maker (CODM) and other items, and also require the annual disclosures on an interim basis. This guidance is effective for annual periods beginning after December 15, 2023, with early adoption permitted. The Company is currently evaluating the impact the new standard will have on its financial statements and related disclosures.
Revenue Recognition
The Company’s revenues are primarily derived from its interests in the sales of oil and natural gas production. The Company recognizes revenue from its interests in the sales of crude oil and natural gas in the period that its performance obligations are satisfied. Performance obligations are satisfied when the customer obtains control of the product, when the Company has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sales of oil and natural gas are made under contracts which the third-party operators of the wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company receives payment from the sale of oil and natural gas production from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in trade receivables, net in the condensed balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant. Accordingly, the variable consideration is not constrained.
The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption, which applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
The Company’s oil is typically sold at delivery points under contract terms that are common in our industry. The Company’s natural gas produced is delivered by the well operators to various purchasers at agreed upon delivery points under a limited number of contract types that are also common in our industry. Regardless of the contract type, the terms of these contracts compensate the well operators for the value of the oil and natural gas at specified prices, and then the well operators will remit payment to the Company for its share in the value of the oil and natural gas sold.
The Company’s disaggregated revenue has two primary sources: oil sales and natural gas and NGL sales. Substantially all of the Company’s oil and natural gas sales during the periods presented came from three geographic areas in the United States: the Williston Basin, the Permian Basin, and the Appalachian Basin. The following tables present the disaggregation of the Company’s oil revenues and natural gas and NGL revenues by basin for the three and nine months ended September 30, 2024 and 2023.
Concentrations of Market, Credit Risk and Other Risks
The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas. The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.
The Company operates in the exploration, development and production sector of the crude oil and natural gas industry. The Company’s receivables include amounts due, indirectly via the third-party operators of the wells, from purchasers of its crude oil and natural gas production. While certain of these customers, as well as third-party operators of the wells, are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations have been immaterial.
As a non-operator, 100% of the Company’s wells are operated by third-party operating partners. As a result, the Company is highly dependent on the success of these third-party operators. If they are not successful in the exploration, development and production activities relating to the Company’s leasehold interests, or are unable or unwilling to perform, the Company’s financial condition and results of operation could be adversely affected. These risks are heightened in a low commodity price environment, which may present significant challenges to these third-party operators. The Company’s third-party operators will make decisions in connection with their operations that may not be in the Company’s best interests, and the Company may have little or no ability to exercise influence over the operational decisions of its third-party operators. For the three months ended September 30, 2024, the Company’s top four operators made up 40% of total oil and natural gas sales, with one operator comprising of more than 10% but less than 15%. For the nine months ended September 30, 2024, the Company’s top four operators made up 39% of total oil and natural gas sales, with one operator comprising of more than 10% but less than 15%. For the three months ended September 30, 2023, the Company’s top four operators made up 41% of total oil and natural gas sales, with two operators comprising of more than 10% but less than 15%. For the nine months ended September 30, 2023, the Company’s top four operators made up 40% of total oil and natural gas sales, with three operators comprising of more than 10% but less than 15%.
The Company faces concentration risk due to the fact that substantially all of its oil and natural gas revenue is sourced from a limited number of geographic areas of operations. As a result, the Company is disproportionately exposed to risks that affect one or more of those areas in the basins in which the Company operates, particularly the Williston Basin and the Permian Basin.
The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its counterparties is generally high. In the normal course of business, letters of credit or parent guarantees may be required for counterparties which management perceives to have a higher credit risk.
Net Income Per Common Share
Basic earnings per share (“EPS”) are computed by dividing net income attributable to common stockholders (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income attributable to common stockholders by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include shares issuable upon exercise of
stock warrants and vesting of restricted stock awards, and shares issuable upon conversion of the Convertible Notes (see Note 4). The number of potential common shares outstanding are calculated using the treasury stock or if-converted method.
In those reporting periods in which the Company has reported net income available to common stockholders, anti-dilutive shares generally are comprised of the restricted stock that has average unrecognized stock compensation expense greater than the average stock price. In those reporting periods in which the Company has a net loss, anti-dilutive shares are comprised of the impact of those number of shares that would have been dilutive had the Company had net income plus the number of common stock equivalents that would be anti-dilutive had the company had net income.
Restricted stock awards are excluded from the calculation of basic weighted average common shares outstanding until they vest. For restricted stock awards that vest based on achievement of performance and/or market conditions, the number of contingently issuable common shares included in diluted weighted-average common shares outstanding is based on the number of common shares, if any, that would be issuable under the terms of the arrangement if the performance and/or market conditions were met at the end of the reporting period, assuming the result would be dilutive.
The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2024 and 2023 are as follows:
Three Months Ended September 30,
Nine Months Ended September 30,
(In thousands, except share and per share data)
2024
2023
2024
2023
Net Income
$
298,446
$
26,111
$
448,609
$
534,116
Weighted Average Common Shares Outstanding:
Weighted Average Common Shares Outstanding – Basic
99,494,313
92,768,035
100,065,656
88,857,016
Plus: Dilutive Effect of Restricted Stock and Common Stock Warrants
1,114,845
539,429
1,096,297
446,141
Plus: Dilutive Effect of Convertible Notes
115,626
434,944
284,614
146,574
Weighted Average Common Shares Outstanding – Diluted
100,724,784
93,742,407
101,446,567
89,449,731
Net Income per Common Share:
Basic
$
3.00
$
0.28
$
4.48
$
6.01
Diluted
$
2.96
$
0.28
$
4.42
$
5.97
Shares Excluded from EPS Due to Anti-Dilutive Effect:
Restricted Stock
180
—
5,495
1,934
Supplemental Cash Flow Information
The following reflects the Company’s supplemental cash flow information:
Cash Paid During the Period for Interest, Net of Amount Capitalized
$
106,228
$
94,441
Cash Paid During the Period for Income Taxes
332
891
Non-cash Investing Activities:
Capital Expenditures on Oil and Natural Gas Properties Included in Accounts Payable and Accrued Liabilities
232,620
281,451
Accrued Liabilities From Acquisitions of Oil and Natural Gas Properties
—
5,168
Capitalized Asset Retirement Obligations
5,295
4,019
Compensation Capitalized on Oil and Gas Properties
—
223
Issuance of Common Stock - Acquisition of Oil and Natural Gas Properties
3,737
—
Non-cash Financing Activities:
Issuance of Common Stock in Exchange for Warrants
23,338
13,328
Common Stock Dividends Declared, But Not Paid
42,092
35,543
Repurchases of Common Stock - Excise Tax
693
—
NOTE 3 CRUDE OIL AND NATURAL GAS PROPERTIES
The Company follows the full cost method of accounting to account for its crude oil and natural gas operations, whereby all costs related to the exploration and development of crude oil and natural gas properties are capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred.
Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the Company’s oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The Company did not have any impairment of its oil and gas properties for the three and nine months ended September 30, 2024 and 2023. Average commodity prices have declined in recent months. If this downward trend continues, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline significantly, which could trigger the need for the Company to record a non-cash ceiling test impairment of its oil and gas property costs in future periods.
The book value of the Company’s crude oil and natural gas properties consists of all acquisition costs (including cash expenditures and the value of stock consideration, as applicable), drilling costs and other associated capitalized costs. Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying condensed statements of operations from the closing date of the acquisition.
2024 Acquisitions
In addition to the closing of the Delaware Acquisition and the Point Acquisition (as defined below), during the three and nine months ended September 30, 2024, the Company acquired oil and natural gas properties through a number of smaller independent transactions for a total of $11.1 million and $26.0 million, respectively.
Delaware Acquisition
In January 2024, the Company completed its acquisition of certain oil and gas properties, interests and related assets in the Delaware Basin from a private seller, effective as of November 1, 2023 (the “Delaware Acquisition”).
The total consideration paid to the seller at closing included 107,657 shares of common stock and $147.8 million in cash, a portion of which was funded by a $17.1 million deposit paid at signing in November 2023.
The results of operations from the date of the Delaware Acquisition through September 30, 2024 represented approximately $33.1 million of revenue and $14.7 million of income from operations. The Company accounted for the Delaware Acquisition as a business combination. Accordingly, transaction costs of approximately $0.6 million were included in general and administrative expense in the Company’s condensed statements of operations. The following table reflects the fair values of the net assets and liabilities as of the closing date of the acquisition:
(In thousands)
Fair value of net assets:
Proved oil and natural gas properties
$
151,912
Total assets acquired
151,912
Asset retirement obligations
(380)
Net assets acquired
$
151,531
Fair value of consideration paid for net assets:
Cash consideration
$
147,794
Non-cash consideration
3,737
Total fair value of consideration transferred
$
151,531
Point Acquisition
In September 2024, the Company completed its acquisition of certain oil and gas properties located in the Delaware Basin, with an effective date of April 1, 2024 from Point Energy (the “Point Acquisition”). The total purchase price incurred by the Company was approximately $200.6 million, consisting of (i) approximately $197.8 million cash payment to the seller, inclusive of $22.0 million acquisition deposit, net of certain customary purchase price adjustments, and (ii) approximately $2.8 million transaction costs.
The Company accounted for the Point Acquisition as an asset acquisition, as substantially all of the fair value of the gross assets acquired were concentrated in a group of similar identifiable assets. Accordingly, the $2.8 million transaction costs were capitalized to the full cost pool of the oil and gas properties acquired.
XCL Acquisition
Subsequent to September 30, 2024, in October 2024, the Company completed its acquisition of certain oil and gas properties in the Uinta Basin from XCL Resources, LLC and certain affiliated entities (“XCL”), effective as of May 1, 2024 (the “XCL Acquisition”). At closing, the Company acquired a 20% undivided working interest in the assets sold by XCL, with SM Energy Company, an unaffiliated third party, acquiring the other 80% and becoming the operator of the acquired assets.
The total purchase price incurred by the Company was approximately $519.0 million, consisting of approximately $511.3 million cash payment to the seller, net of certain customary purchase price adjustments, and approximately $7.7 million transaction costs.
2023 Acquisitions
During 2023, the Company completed the following larger bolt-on acquisitions (each as defined and described below): the MPDC Acquisition, the Forge Acquisition and the Novo Acquisition (collectively, the “2023 Bolt-on Acquisitions”).
During 2023, in addition to the 2023 Bolt-on Acquisitions, during the three and nine months ended September 30, 2023, the Company acquired oil and natural gas properties through a number of smaller independent transactions for a total of $113.6 million and $172.0 million, respectively.
MPDC Acquisition
In January 2023, the Company completed its acquisition (the “MPDC Acquisition”) of certain oil and gas properties, interests and related assets from Midland Petro D.C. Partners, LLC and Collegiate Midstream LLC (collectively, “MPDC”), effective as
of August 1, 2022. At closing, the Company acquired a 39.958% working interest in MPDC’s four-unit development project in the Permian Midland Basin, which includes an interest in gathering assets associated with the project.
The total consideration at closing was $319.9 million in cash. As a result of customary post-closing adjustments, the Company reduced its proved oil and natural gas properties and total consideration by $8.2 million subsequent to closing.
The results of operations from the date of the MPDC Acquisition through December 31, 2023 represented approximately $157.0 million of revenue and $102.3 million of income from operations. The Company accounting for the MPDC Acquisition as a business combination. Accordingly, transaction costs of approximately $3.5 million were included in general and administrative expense in the Company’s condensed statements of operations. The following table reflects the fair values of the net assets and liabilities as of the closing date of the acquisition:
(In thousands)
Fair value of net assets:
Proved oil and natural gas properties
$
320,395
Total assets acquired
320,395
Asset retirement obligations
(451)
Net assets acquired
$
319,944
Fair value of consideration paid for net assets:
Cash consideration
$
319,944
Total fair value of consideration transferred
$
319,944
Forge Acquisition
In June 2023, the Company completed its acquisition (the “Forge Acquisition”) of certain Permian Delaware Basin assets from Forge Energy II Delaware, LLC (“Forge”), effective as of March 1, 2023. At closing, the Company acquired a 30% undivided stake in the assets sold by Forge, with Vital Energy, Inc., an unaffiliated third party, acquiring the other 70% and becoming the operator of the acquired assets.
The total consideration at closing, net to the Company, was $167.9 million in cash. As a result of customary post-closing adjustments, the Company reduced its proved oil and natural gas properties and total consideration by $0.7 million subsequent to closing.
The results of operations from the date of the Forge Acquisition through December 31, 2023 represented approximately $46.0 million of revenue and $29.3 million of income from operations. The Company accounted for the Forge Acquisition as a business combination. Accordingly, transactions costs of approximately $2.3 million were included in general and administrative expense in the Company’s condensed statements of operations. The following table reflects the fair values of the net assets and liabilities as of the closing date of the acquisition:
In August 2023, the Company completed its acquisition (the “Novo Acquisition”) of certain Permian Delaware Basin assets of Novo Oil & Gas Holdings, LLC (“Novo”), effective as of May 1, 2023. At closing, the Company acquired a 33.33% undivided stake in the assets sold by Novo to Earthstone Energy Holdings, LLC (“Earthstone”), an unaffiliated third party, with Earthstone retaining the other 66.67% and becoming operator of the acquired assets.
The total consideration at closing, net to the Company, was $468.4 million in cash. As a result of customary post-closing adjustments, the Company reduced its proved oil and natural gas properties and total consideration by $1.2 million subsequent to closing.
The results of operations from the date of the Novo Acquisition through December 31, 2023 represented approximately $78.5 million of revenue and $40.9 million of income from operations. The Company accounted for the Novo Acquisition as a business combination. Accordingly, transaction costs of approximately $4.6 million were included in general and administrative expense in the Company’s condensed statements of operations. The following table reflects the fair values of the net assets and liabilities as of the closing date of the acquisition:
(In thousands)
Fair value of net assets:
Proved oil and natural gas properties
$
474,417
Total assets acquired
474,417
Asset retirement obligations
(813)
Accrued Liabilities
(5,168)
Net assets acquired
$
468,436
Fair value of consideration paid for net assets:
Cash consideration
$
468,436
Total fair value of consideration transferred
$
468,436
Pro Forma Information
The following summarized unaudited pro forma condensed statement of operations information for the three and nine months ended September 30, 2024 and 2023, provides summarized information for the acquisitions accounted for as business combinations. The information provided assumes that the acquisitions accounted for as business combinations occurred as of January 1, 2023. There is no pro forma information included for the three months ended September 30, 2024, because the Company’s actual financial results for such period fully reflect all such acquisitions. The Company prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had the Company completed the acquisitions as of January 1, 2023, or that would be attained in the future.
Nine Months Ended
Three Months Ended
Nine Months Ended
(In thousands)
September 30, 2024
September 30, 2023
September 30, 2023
Total Revenues
$
1,713,702
$
361,493
$
1,711,730
Net Income
450,283
91,620
803,355
Unproved Properties
All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion until the properties are evaluated for reserves. Once a property is evaluated, all associated acreage and drilling costs are subject to depletion.
The Company historically has acquired unproved properties by purchasing individual or small groups of leases directly from mineral owners, landmen, or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. The Company generally participates in
drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling.
The Company believes that the majority of its unproved property will be evaluated, and thus the related costs will become subject to depletion within the next five years. The timing by which all unproved properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves.
Capitalized costs associated with evaluated leasehold costs, which includes leases that have expired or have been deemed uneconomic, and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized using the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period. The costs of unproved properties are withheld from the depletion base until such time that they are evaluated.
When unproved properties are evaluated, their cost is added to costs subject to depletion and full cost ceiling calculations. For the three months ended September 30, 2024 and 2023, unproved properties of $1.6 million and $1.4 million, respectively, were transferred to evaluated leasehold costs, due to lease expirations. For the nine months ended September 30, 2024 and 2023, unproved properties of $3.3 million and $4.1 million, respectively were transferred to evaluated leasehold costs due to lease expirations.
NOTE 4 LONG-TERM DEBT
The Company’s long-term debt consists of the following:
September 30, 2024
(In thousands)
Principal Balance
Unamortized Premium/(Discount)
Debt Issuance Costs, Net
Long-term Debt, Net
Revolving Credit Facility (1)
$
275,000
$
—
$
—
$
275,000
Senior Notes due 2028
705,108
6,856
(7,667)
704,297
Convertible Notes due 2029
500,000
—
(12,393)
487,607
Senior Notes due 2031
500,000
(5,936)
(7,869)
486,195
Total
$
1,980,108
$
920
$
(27,929)
$
1,953,099
December 31, 2023
Principal Balance
Unamortized Premium/(Discount)
Debt Issuance Costs, Net
Long-term Debt, Net
Revolving Credit Facility (1)
$
161,000
$
—
$
—
$
161,000
Senior Notes due 2028
705,108
8,376
(9,366)
704,117
Convertible Notes due 2029
500,000
—
(14,214)
485,786
Senior Notes due 2031
500,000
(6,600)
(8,749)
484,651
Total
$
1,866,108
$
1,776
$
(32,330)
$
1,835,554
________________
(1)Debt issuance costs related to the Company’s Revolving Credit Facility of $9.9 million and $10.6 million as of September 30, 2024 and December 31, 2023, are recorded in “Other Noncurrent Assets, Net” in the balance sheets.
Revolving Credit Facility
On June 7, 2022, the Company entered into a Third Amended and Restated Credit Agreement (as amended, modified, or supplemented through the date of this filing, the “Revolving Credit Facility”) with Wells Fargo Bank, National Association, as administrative agent and collateral agent (“Agent”), and the lenders from time to time party thereto, which amended and restated the Company’s prior revolving credit facility that was entered into on November 22, 2019. The Revolving Credit Facility is scheduled to mature on June 7, 2027.
The Revolving Credit Facility is comprised of revolving loans and letters of credit and is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to the Company and its subsidiaries’ (if any) oil and gas properties. As of September 30, 2024, the borrowing base was $1.8 billion and the aggregate elected commitment amount was $1.5 billion. The Company’s borrowing availability under the Revolving Credit Facility is set at the lesser of the borrowing base and the elected commitment amount. The borrowing base will be redetermined semiannually on or around April 1 and October 1, with one interim “wildcard” redetermination available to each of the Company and the Agent (acting at the direction of the lenders holding at least two-thirds of commitments and loans outstanding under the Revolving Credit Facility) between scheduled redeterminations. Upon an acquisition of oil and gas properties with an aggregate value exceeding 5% of the borrowing base, the Company may request an additional redetermination. The scheduled redeterminations are based on a December 31 or June 30 reserve report, as applicable, prepared under the supervision of the Company’s chief engineer and, in the case of the December 31 reserve report, audited by an approved petroleum engineer (reasonably acceptable to the Agent). The Company has the option to seek commitments for term loans, which such term loans (if obtained) are capped at the least of (i) the borrowing base minus the aggregate elected commitment amount minus the then-outstanding principal amount of term loans, (ii) the aggregate elected commitment amount minus the then-outstanding principal amount of term loans and (iii) $500.0 million. Such term loans are subject to certain other terms of the Revolving Credit Facility.
At the Company’s option, borrowings under the Revolving Credit Facility shall bear interest at the base rate or SOFR plus an applicable margin. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the Agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted SOFR rate for a one-month interest period plus 100 basis points. The applicable margin for base rate loans ranges from 125 to 225 basis points, and the applicable margin for SOFR loans ranges from 225 to 325 basis points, in each case depending on the percentage of the borrowing base utilized.
The Revolving Credit Facility contains negative covenants that limit the Company’s ability, among other things, to pay dividends, incur additional indebtedness, sell assets, enter into certain derivatives contracts, change the nature of its business or operations, merge, consolidate, or make certain types of investments. In addition, the Revolving Credit Facility requires that the Company comply with the following financial covenants: (i) as of the date of determination, the ratio of total net debt to EBITDAX (as defined in the Revolving Credit Facility) shall be no more than 3.50 to 1.00, measured on a rolling four quarter basis, and (ii) the current ratio (defined as consolidated current assets including unused amounts of the total commitments, but excluding non-cash assets under FASB Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging (“ASC 815”), divided by consolidated current liabilities excluding current non-cash obligations under ASC 815, current maturities under the Revolving Credit Facility and current maturities of any long-term debt) shall not be less than 1.00 to 1.00. The Company is in compliance with these financial covenants as of September 30, 2024.
The Company’s obligations under the Revolving Credit Facility may be accelerated, subject to customary grace and cure periods, upon the occurrence of certain Events of Default (as defined in the Revolving Credit Facility). Such Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, defaults related to judgments and the occurrence of a Change in Control (as defined in the Revolving Credit Facility).
The Company’s obligations under the Revolving Credit Facility are secured by mortgages on not less than 90% of the value of proven reserves associated with the oil and gas properties included in the determination of the borrowing base. Additionally, the Company entered into a Guaranty and Collateral Agreement in favor of the Agent for the secured parties, pursuant to which the Company’s obligations under the Revolving Credit Facility are secured by a first priority security interest in substantially all of the Company’s assets.
Senior Notes due 2028
On February 18, 2021, the Company and Wilmington Trust, National Association, as trustee, entered into an indenture (the “2028 Notes Indenture”), pursuant to which the Company issued $550.0 million in aggregate principal amount of 8.125% senior notes due 2028 (the “Original 2028 Notes”). On November 15, 2021, the Company issued an additional $200.0 million aggregate principal amount of 8.125% senior notes due 2028 (the “Additional 2028 Notes” and, together with the Original 2028 Notes, the “Senior Notes due 2028”). The proceeds of the Senior Notes due 2028 were used primarily to refinance existing indebtedness, and for general corporate purposes.
During the nine months ended September 30, 2023, the Company repurchased and retired $19.1 million in aggregate principal amount of the Senior Notes due 2028 in open market transactions for a total of $18.4 million in cash, plus accrued interest.
The Senior Notes due 2028 will mature on March 1, 2028. Interest is payable semi-annually in arrears on each March 1 and September 1 to holders of record on the February 15 and August 15 immediately preceding the related interest payment date, at a rate of 8.125% per annum. The Company may redeem all or a part of the Senior Notes due 2028 at redemption prices (expressed as percentages of principal amount) equal to 104.063% through February 28, 2025, 102.031% for the twelve-month period beginning on March 1, 2025, and 100% beginning on March 1, 2026, plus accrued and unpaid interest to the redemption date.
If a Change of Control Triggering Event (as defined in the 2028 Notes Indenture) occurs, each holder of Senior Notes due 2028 may require the Company to repurchase all or any part of that holder’s the Senior Notes due 2028 for cash at a price equal to 101% of the aggregate principal amount of the Senior Notes due 2028 repurchased, plus any accrued and unpaid interest on the Senior Notes due 2028 repurchased to, but excluding, the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date on or prior to the date of purchase).
The 2028 Notes Indenture contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries, if any, to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends or distributions in respect of equity interests or redeem, repurchase or retire equity securities or subordinated indebtedness; (iii) transfer or sell certain assets; (iv) make investments; (v) create liens to secure indebtedness; (vi) enter into agreements that restrict dividends or other payments from any non-guarantor subsidiary to the Company; (vii) consolidate with or merge with or into, or sell substantially all of the Company’s assets to, another person; (viii) enter into transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications, and many of these covenants will be terminated if the Senior Notes due 2028 achieve an investment grade rating from either Moody’s Investors Services, Inc. or S&P Global Ratings.
The 2028 Notes Indenture contains customary events of default, including, but not limited to: (i) default for 30 days in the payment when due of interest on the Senior Notes due 2028; (ii) default in payment when due of the principal of, or premium, if any, on the Senior Notes due 2028; (iii) failure by the Company or certain of its subsidiaries, if any, to comply with certain of their respective obligations, covenants or agreements contained in the Senior Notes due 2028 or the 2028 Notes Indenture, subject to certain notice and grace periods; (iv) failure by the Company or any of its restricted subsidiaries to pay indebtedness within any applicable grace period or the acceleration of any such indebtedness if the total amount of such indebtedness exceeds $35.0 million; (v) failure by the Company or any of its restricted subsidiaries that is a Significant Subsidiary (as defined in the 2028 Notes Indenture) to pay final non-appealable judgments aggregating in excess of $35.0 million, which judgments are not paid, discharged or stayed for a period of 60 days; (vi) except as permitted by the 2028 Notes Indenture, any guarantee of the Senior Notes due 2028 is held in any judicial proceeding to be unenforceable or invalid, or ceases for any reason to be in full force and effect, or is denied or disaffirmed by a Guarantor (as defined in the 2028 Notes Indenture); and (vii) certain events of bankruptcy or insolvency described in the 2028 Notes Indenture with respect to the Company and its restricted subsidiaries that are Significant Subsidiaries.
Convertible Notes due 2029
On October 14, 2022, the Company and Wilmington Trust, National Association, as trustee, entered into an indenture (the “Convertible Notes Indenture”), pursuant to which the Company issued $500.0 million in aggregate principal amount of 3.625% convertible senior notes due 2029 (the “Convertible Notes”). The proceeds of the Convertible Notes were used to refinance existing indebtedness and for other general corporate purposes. The Convertible Notes mature on April 15, 2029, unless earlier repurchased, redeemed or converted. The Convertible Notes accrue interest at a rate of 3.625% per annum, payable semi-annually in arrears on April 15 and October 15 of each year.
Before October 16, 2028, noteholders have the right to convert their Convertible Notes only upon the occurrence of certain events. From and after October 16, 2028, noteholders may convert their Convertible Notes at any time at their election until the close of business on the second scheduled trading day immediately before the maturity date. The Company will have the right to elect to settle conversions either entirely in cash or in a combination of cash and shares of its common stock. However, upon conversion of any Convertible Notes, the conversion value, which will be determined over a period of 40 trading days, will be paid in cash up to at least the principal amount of the Convertible Notes being converted. The initial conversion rate was 26.3104 shares of common stock per $1,000 principal amount of Convertible Notes, which represented an initial conversion price of approximately $38.01 per share of common stock. The conversion rate and conversion price are subject to customary anti-dilution and other adjustments upon the occurrence of certain events. As of September 30, 2024, the conversion rate was 26.7584 shares of common stock per $1,000 principal amount of Convertible Notes, which represented a conversion price of approximately $37.37 per share of common stock. In addition, if certain corporate events that constitute a “Make-Whole Fundamental Change” (as defined in the Convertible Notes Indenture) occur, then the conversion rate will, in certain circumstances, be increased for a specified period of time.
The Convertible Notes are redeemable, in whole or in part (subject to certain limitations), at the Company’s option at any time, and from time to time, on or after April 15, 2026 and on or before the 40th scheduled trading day immediately before the maturity date, at a cash redemption price equal to the principal amount of the Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date, but only if the last reported sale price per share of the Company’s common stock exceeds 130% of the conversion price on (i) each of at least 20 trading days, whether or not consecutive, during the 30 consecutive trading days ending on, and including, the trading day immediately before the date the Company sends the related redemption notice; and (ii) the trading day immediately before the date the Company sends such notice. In addition, calling any Convertible Note for redemption will constitute a Make-Whole Fundamental Change with respect to that Convertible Note, in which case the conversion rate applicable to the conversion of that Convertible Note will be increased in certain circumstances if it is converted after it is called for redemption.
If certain corporate events that constitute a “Fundamental Change” (as defined in the Convertible Notes Indenture) occur, then, subject to a limited exception for certain cash mergers, noteholders may require the Company to repurchase their Convertible Notes at a cash repurchase price equal to the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. The definition of Fundamental Change includes certain business combination transactions involving the Company and certain de-listing events with respect to the Company’s common stock.
The Convertible Notes have customary provisions relating to the occurrence of “Events of Default” (as defined in the Convertible Notes Indenture), which include the following: (i) certain payment defaults on the Convertible Notes (which, in the case of a default in the payment of interest on the Convertible Notes, will be subject to a 30-day cure period); (ii) the Company’s failure to send certain notices under the Convertible Notes Indenture within specified periods of time; (iii) the Company’s failure to comply with certain covenants in the Convertible Notes Indenture relating to the Company’s ability to consolidate with or merge with or into, or sell, lease or otherwise transfer, in one transaction or a series of transactions, all or substantially all of the assets of the Company and any subsidiaries that the Company may form or acquire in the future, taken as a whole, to another person; (iv) a default by the Company in certain of its other obligations or agreements under the Convertible Notes Indenture or the Convertible Notes if such default is not cured or waived within 60 days after notice is given in accordance with the Convertible Notes Indenture; (v) certain defaults by the Company or any subsidiaries that the Company may form or acquire in the future with respect to indebtedness for borrowed money of at least $50.0 million; (vi) the rendering of certain judgments against the Company or any of its subsidiaries for the payment of at least $50.0 million, where such judgments are not paid, discharged or stayed within 60 days after the date on which the right to appeal has expired or on which all rights to appeal have been extinguished; and (vii) certain events of bankruptcy, insolvency and reorganization involving the Company or any of the Company’s significant subsidiaries that the Company may form or acquire in the future.
If an Event of Default involving bankruptcy, insolvency or reorganization events with respect to the Company (and not solely with respect to any significant subsidiary that the Company may form or acquire in the future) occurs, then the principal amount of, and all accrued and unpaid interest on, all of the Convertible Notes then outstanding will immediately become due and payable without any further action or notice by any person. If any other Event of Default occurs and is continuing, then, the Trustee (as defined in the Convertible Notes Indenture), by notice to the Company, or noteholders of at least 25% of the aggregate principal amount of Convertible Notes then outstanding, by notice to the Company and the Trustee, may declare the principal amount of, and all accrued and unpaid interest on, all of the Convertible Notes then outstanding to become due and payable immediately. However, notwithstanding the foregoing, the Company may elect, at its option, that the sole remedy for an Event of Default relating to certain failures by the Company to comply with certain reporting covenants in the Convertible Notes Indenture consists exclusively of the right of the noteholders to receive special interest on the Convertible Notes for up to 365 days at a specified rate per annum not exceeding 0.25% on the principal amount of the Convertible Notes for the first 180 days and, thereafter, at a specified rate per annum not exceeding 0.50% on the principal amount of the Convertible Notes.
Capped Call Transactions
In October 2022, in connection with the Convertible Notes offering described above, the Company entered into privately negotiated capped call transactions (the “Capped Call Transactions”) with certain of the initial purchasers of the Convertible Notes and/or their respective affiliates and/or other financial institutions. The Company paid $36.1 million in total consideration to enter into the Capped Call Transactions. The Capped Call Transactions cover, subject to anti-dilution adjustments substantially similar to those applicable to the conversion rate of the Convertible Notes, the number of shares of common stock initially underlying the Convertible Notes. The Capped Call Transactions are expected generally to reduce potential dilution to the common stock upon any conversion of Convertible Notes and/or offset any potential cash payments the Company is required to make in excess of the principal amount of such converted Convertible Notes, as the case may be, with such reduction and/or offset subject to a cap. The cap price of the Capped Call Transactions was initially approximately $52.17 per share of common stock, which represents a premium of 75% over the last reported sale price of the common stock of $29.81 per
share on October 11, 2022, and is subject to certain customary adjustments under the terms of the Capped Call Transactions. As of September 30, 2024, the cap price of the Capped Call Transactions was approximately $51.29 per share of common stock.
Senior Notes due 2031
On May 15, 2023, the Company and Wilmington Trust, National Association, as trustee, entered into an indenture (the “2031 Notes Indenture”), pursuant to which the Company issued $500.0 million in aggregate principal amount of the Company’s 8.750% senior notes due 2031 (the “Senior Notes due 2031”). The proceeds of the Senior Notes due 2031 were used primarily to refinance existing indebtedness, and for general corporate purposes.
The Senior Notes due 2031 will mature on June 15, 2031. Interest is payable semi-annually in arrears on each June 15 and December 15, to holders of record on the June 1 and December 1 immediately preceding the related interest payment date, at a rate of 8.750% per annum. Prior to June 15, 2026, the Company may redeem up to 35% of the aggregate principal amount of Senior Notes due 2031, upon not less than 10 or more than 60 days’ notice, at a redemption price of 108.750% of the principal amount of the Senior Notes due 2031 redeemed, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), in an amount not greater than the net cash proceeds of one or more equity offerings by the Company, provided that (i) at least 65% of the aggregate principal amount of Senior Notes due 2031 issued under the 2031 Notes Indenture (including any Additional Notes (as defined in the 2031 Notes Indenture) but excluding the Senior Notes due 2031 held by the Company and its Subsidiaries (as defined in the 2031 Notes Indenture)) remains outstanding immediately after the occurrence of such redemption (unless all Senior Notes due 2031 are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days of the date of the closing of each such equity offering. In addition, prior to June 15, 2026, the Company may redeem all or a part of the Senior Notes due 2031, on any one or more occasions, upon not less than 10 or more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the Senior Notes due 2031 redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to, but excluding, the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).
On or after June 15, 2026, the Company may redeem all or a part of the Senior Notes due 2031 at redemption prices (expressed as percentages of principal amount) equal to 104.375% for the twelve-month period beginning on June 15, 2026, 102.188% for the twelve-month period beginning on June 15, 2027, and 100% beginning on June 15, 2028, plus accrued and unpaid interest to the redemption date.
If a Change of Control Triggering Event (as defined in the 2031 Notes Indenture) occurs, each holder of Senior Notes due 2031 may require the Company to repurchase all or any part of that holder’s Senior Notes due 2031 for cash at a price equal to 101% of the aggregate principal amount of the Senior Notes due 2031 repurchased, plus any accrued and unpaid interest on the Senior Notes due 2031 repurchased to, but excluding, the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date on or prior to the date of purchase).
The 2031 Notes Indenture contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries, if any, to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends or distributions in respect of equity interests or redeem, repurchase or retire equity securities or subordinated indebtedness; (iii) transfer or sell certain assets; (iv) make investments; (v) create liens to secure indebtedness; (vi) enter into agreements that restrict dividends or other payments from any non-guarantor subsidiary to the Company; (vii) consolidate with or merge with or into, or sell substantially all of the Company’s assets to, another person; (viii) enter into transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications, and many of these covenants will be terminated if the Senior Notes due 2031 achieve an investment grade rating from either Moody’s Investors Service, Inc. or S&P Global Ratings.
The 2031 Notes Indenture contains customary events of default, including, but not limited to: (i) default for 30 days in the payment when due of interest on the Senior Notes due 2031; (ii) default in payment when due of the principal of, or premium, if any, on the Senior Notes due 2031; (iii) failure by the Company or certain of its subsidiaries, if any, to comply with certain of their respective obligations, covenants or agreements contained in the Senior Notes due 2031 or the 2031 Notes Indenture, subject to certain notice and grace periods; (iv) failure by the Company or any of its restricted subsidiaries to pay indebtedness within any applicable grace period or the acceleration of any such indebtedness if the total amount of such indebtedness exceeds $35.0 million; (v) failure by the Company or any of its restricted subsidiaries that is a Significant Subsidiary (as defined in the 2031 Notes Indenture) to pay final non-appealable judgments aggregating in excess of $35.0 million, which judgments are not
paid, discharged or stayed for a period of 60 days; (vi) except as permitted by the 2031 Notes Indenture, any guarantee of the Senior Notes due 2031 is held in any judicial proceeding to be unenforceable or invalid, or ceases for any reason to be in full force and effect, or is denied or disaffirmed by a Guarantor (as defined in the 2031 Notes Indenture); and (vii) certain events of bankruptcy or insolvency described in the 2031 Notes Indenture with respect to the Company and its restricted subsidiaries that are Significant Subsidiaries.
NOTE 5 COMMON AND PREFERRED STOCK
Common Stock
On May 23, 2024, the Company filed an amendment to its certificate of incorporation, which was effective upon filing, to increase the number of authorized shares of common stock, par value 0.001 per share, from 135,000,000 to 270,000,000, as approved by the Company’s stockholders at the 2024 Annual Meeting of Stockholders on May 23, 2024. As of September 30, 2024, the Company had 99,825,164 shares of common stock issued and outstanding.
Preferred Stock
The Company is authorized to issue up to 5,000,000 shares of preferred stock, par value $0.001 per share, with such designations, voting and other rights and preferences as may be determined from time to time by the Company’s board of directors. As of September 30, 2024, the Company had zero shares of preferred stock issued and outstanding.
2024 Activity
Common Stock
During the nine months ended September 30, 2024, 71,548 shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with their restricted stock awards. The total value of these shares surrendered, based on the market prices on the dates the shares were surrendered, was approximately $2.7 million.
During the nine months ended September 30, 2024, the Company issued 656,297 shares of common stock in exchange for the surrender and cancellation of outstanding warrants to purchase common stock, which immediately prior to their cancellation were exercisable for an aggregate of approximately 1,223,963 shares of common stock at an exercise price of $26.33 per share.
During the nine months ended September 30, 2024, the Company issued 107,657 shares of its common stock as partial consideration for the Delaware Acquisition (see Note 3).
Dividends
In February 2024, the Company’s board of directors declared a cash dividend on the Company’s common stock in the amount of $0.40 per share. The dividend was paid on April 30, 2024 to stockholders of record as of the close of business on March 28, 2024.
In May 2024, the Company’s board of directors declared a cash dividend on the Company’s common stock in the amount of $0.40 per share. The dividend was paid on July 31, 2024 to stockholders of record as of the close of business on June 27, 2024.
In August 2024, the Company’s board of directors declared a cash dividend on the Company’s common stock in the amount of $0.42 per share. The dividend was paid on October 31, 2024 to stockholders of record as of the close of business on September 27, 2024.
Stock Repurchase Program
In May 2022, the Company’s board of directors approved a stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock. In July 2024, the Company’s board of directors terminated the prior stock repurchase program, which was substantially depleted, and approved a new stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.
During the nine months ended September 30, 2024, the Company repurchased 1,841,733 shares of its common stock for $70.0 million (including commissions and $0.7 million in excise tax) under the Company’s stock repurchase program. During the nine months ended September 30, 2023, the Company repurchased 287,751 shares of its common stock under the Company’s stock repurchase program at a total cost of $8.0 million.
The Company’s accounting policy upon the repurchase of shares is to deduct its par value from common stock and to reflect any excess of cost over par value as a deduction from Additional Paid-in Capital. All repurchased shares are included in the Company’s pool of authorized but unissued shares.
NOTE 6 STOCK-BASED COMPENSATION AND WARRANTS
Stock-Based Compensation
The Company maintains the Amended and Restated 2018 Equity Incentive Plan (the “2018 Plan”) for the purpose of making equity-based awards to employees, directors and other eligible persons. As of September 30, 2024, there were 2,791,373 shares available for future awards or settlement of awards under the 2018 Plan.
The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company’s stock-based compensation awards are accounted for as equity instruments and are included in the “General and administrative expenses” line item in the unaudited condensed statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included in the “Oil and natural gas properties” line item in the unaudited condensed balance sheets.
Issuances made pursuant to the 2018 Plan are summarized as follows:
The Company issues share-based awards in the form of restricted stock awards (“RSAs”), restricted stock units (“RSUs”) and share appreciation awards (“SARs”), subject to various vesting conditions, as compensation to executive officers, employees and directors of the Company. Typically, RSAs issued to employees and executive officers contain a service condition only and generally vest over three or four years. Typically, RSUs and SARs contain both a service and market condition. Market conditions can be the Company’s absolute total shareholder return (“TSR”), the Company’s TSR ranking among its peer companies or the Company’s market capitalization growth measured over a defined performance period. Grantees’ continued employment through the end of the performance period is required for such RSUs and SARs to vest. RSAs issued to directors generally vest either immediately or over one year, subject to continued service and provided that any performance and/or market conditions are also met.
For awards subject to service and/or performance vesting conditions, the grant date fair value is established based on the closing price of the Company’s common stock on such date. Stock-based compensation expense for awards subject to only service conditions is recognized on a straight-line basis over the service period. Stock-based compensation expense for awards subject to both service and performance conditions are recognized on a graded basis if it is probable that the performance condition will be achieved. The Company accounts for forfeitures of awards granted under these plans as they occur in determining stock-based compensation expense.
For awards subject to a market condition, the grant date fair value is estimated using a Monte Carlo valuation model. The Company recognizes stock-based compensation expense for awards subject to market-based vesting conditions regardless of whether the market conditions are achieved or not, and stock-based compensation expense for any such awards is reversed only when the implied service requirement is not met. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility is calculated based on the historical volatility and implied volatility of the Company’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period.
The following table reflects the outstanding service-based RSAs and activity related thereto for the nine months ended September 30, 2024:
Service-based Awards
Number of Shares
Weighted-average Grant Date Fair Value
Outstanding at December 31, 2023
497,722
$
27.45
Shares granted
213,767
36.09
Shares forfeited
(424)
35.41
Shares vested
(192,993)
24.19
Outstanding at September 30, 2024
518,072
$
35.56
At September 30, 2024, there was $13.5 million of total unrecognized compensation expense related to unvested RSAs. That cost is expected to be recognized over a weighted average period of 1.41 years. For the nine months ended September 30, 2024 and 2023, the total fair value of the Company’s RSAs that vested was $5.8 million and $6.2 million, respectively. For the nine months ended September 30, 2024, the compensation expenses associated with these awards were $5.5 million.
In April 2022, the Company granted performance equity awards under its 2022 executive compensation program to certain executive officers. The awards were subject to a market condition and, in January 2023, the market condition was met. Accordingly, the Company issued 74,220 restricted shares of common stock in settlement of these awards, with service-based vesting over three years. The shares are included in the above table.
Performance Equity Awards
The following table reflects the outstanding RSUs that are subject to market conditions linked to TSR (“TSR Awards”) and activity related thereto for the nine months ended September 30, 2024:
TSR Awards
Number of Units
Weighted-average Grant Date Fair Value
Outstanding at December 31, 2023
83,710
$
44.49
Units granted
204,280
36.57
Units forfeited
—
—
Units vested
—
—
Outstanding at September 30, 2024
287,990
$
38.87
For the nine months ended September 30, 2024, the compensation expenses associated with these awards were $1.7 million. As of September 30, 2024, the unrecognized compensation expenses for these awards were $9.5 million, which will be amortized over the remaining performance period.
In December 2023, the Company also granted performance equity awards, in the form of SARs. The final payout (if any) will be a dollar amount, which may be settled in cash, shares or a combination of both at the Company’s option. The Company plans to settle the SARs Awards that were granted in 2023 with shares. For the nine months ended September 30, 2024, the compensation expenses associated with these awards were $1.1 million. As of September 30, 2024, the unrecognized compensation expenses for these awards were $4.8 million, which will be amortized over the remaining performance period.
The Company used Monte Carlo simulation models, described above, to estimate (i) the fair value of the TSR Awards that were granted in 2023 and 2024 based on the expected outcome of the Company’s absolute TSR as well as TSR relative to the defined peer group and (ii) the fair value of the SARs Awards that were granted in 2023 based on the expected outcome of the Company’s market capitalization appreciation rate. The Company used the following key assumptions in its Monte Carlo simulation models: (i) risk-free rates ranging from 1.7% to 4.2%, (ii) dividend yield ranging from nil to 4.3%, and (iii) expected volatility ranging from 56.4% to 72.3%.
In January 2022, as partial consideration for the purchase of certain oil and gas properties, the Company issued warrants to purchase 1,939,998 shares of the Company’s common stock at an exercise price equal to $28.30 per share (subject to certain anti-dilution adjustments) (the “Warrants”).
In March 2023, the Company issued 403,780 shares of common stock in exchange for the surrender and cancellation of a portion of the Warrants. Immediately prior to their cancellation, such Warrants that were surrendered were exercisable for an aggregate of approximately 824,602 shares of common stock at an exercise price of $27.4946 per share.Neither the Company nor the holders paid any cash consideration in the transaction.
In March 2024, the Company issued 656,297 shares of common stock in exchange for the surrender and cancellation of all of the remaining Warrants. Immediately prior to their cancellation, such Warrants that were surrendered were exercisable for an aggregate of approximately 1,223,963 shares of common stock at an exercise price of $26.3324 per share.Neither the Company nor the holders paid any cash consideration in the transaction.
The following table reflects the outstanding warrants and activity related thereto for the nine months ended September 30, 2024:
Warrants
Number of Warrants
Weighted-average Exercise Price
Outstanding at December 31, 2023
1,223,963
$
26.33
Issued
—
—
Anti-Dilution Adjustments for Common Stock Dividends
—
—
Exercised
—
—
Cancelled
(1,223,963)
26.33
Expired
—
—
Outstanding at September 30, 2024
—
$
—
NOTE 7 COMMITMENTS & CONTINGENCIES
Litigation
The Company is engaged in various proceedings incidental to the normal course of business. Due to their nature, such legal proceedings involve inherent uncertainties, including but not limited to court rulings, negotiations between affected parties and governmental intervention. Based upon the information available to the Company and discussions with legal counsel, it is the Company’s opinion that the outcome of the various legal actions and claims that are incidental to its business will not have a material impact on the Company’s financial position, results of operations or cash flows. Such matters, however, are subject to many uncertainties, and the outcome of any matter is not predictable with assurance.
NOTE 8 INCOME TAXES
Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provision for income taxes for the three and nine months ended September 30, 2024 and 2023 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily due to the non-deductibility of permanent items, state income taxes, and discrete items during the three and nine months ended September 30, 2024, and the release of our valuation allowance on deferred tax assets during the three and nine months ended September 30, 2023, respectively.
In assessing the realizability of deferred tax assets (“DTAs”), management considers whether it is more likely than not that some portion, or all, of the Company’s DTAs will not be realized. In making such determination, the Company considers all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-
forwards, (iii) the projected future income and results of operations, and (iv) its ability to use tax planning strategies. If the Company concludes that it is more likely than not that some portion, or all, of its DTAs will not be realized, the tax asset is reduced by a valuation allowance. The Company assesses the appropriateness of its valuation allowance on a quarterly basis.
The Company had an income tax expense of approximately $98.8 million and an income tax benefit of approximately $20.7 million for the three months ended September 30, 2024 and 2023, respectively. The effective tax rates for the three months ended September 30, 2024 and 2023 were 24.9% and (381.8)%, respectively. The Company’s income tax expense was $144.4 million and $19.0 million for the nine months ended September 30, 2024 and 2023, respectively. The effective tax rates for the nine months ended September 30, 2024 and 2023 were 24.3% and 3.4%, respectively.
NOTE 9 FAIR VALUE
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The Company uses a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following:
Level 1 - Quoted prices in active markets for identical assets or liabilities.
Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
Financial Assets and Liabilities
As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2024 and December 31, 2023:
Fair Value Measurements at September 30, 2024 Using
(In thousands)
Quoted Prices In Active Markets for Identical Assets (Liabilities) (Level 1)
Fair Value Measurements at December 31, 2023 Using
(In thousands)
Quoted Prices In Active Markets for Identical Assets (Liabilities) (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
Commodity Derivatives – Current Assets
$
—
$
75,733
$
—
Commodity Derivatives – Noncurrent Assets
—
10,725
—
Commodity Derivatives – Current Liabilities
—
(16,797)
—
Commodity Derivatives – Noncurrent Liabilities
—
(105,831)
—
Total
$
—
$
(36,169)
$
—
Commodity Derivatives. The Level 2 instruments presented in the tables above include commodity derivative instruments (see Note 10). The fair value of the Company’s commodity derivative instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company’s and the counterparties’ nonperformance risk is evaluated. The fair value of commodity derivative contracts is reflected in the condensed balance sheet. The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months.
Interest Rate Derivatives. The Level 2 instruments presented in the tables above include interest rate derivative instruments. The fair value of the Company’s interest rate derivative instruments is determined based upon contracted notional amounts, active market-quoted interest yield curves, and time to maturity, among other things. Counterparty statements are utilized to determine the value of the interest rate derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company’s and the counterparties’ nonperformance risk is evaluated. The fair value of interest rate derivative contracts is reflected in the balance sheets. The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months.
Fair Value of Other Financial Instruments
The carrying amounts of cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments.
Long-term debt is not presented at fair value in the balance sheets, as it is recorded at carrying value, net of unamortized debt issuance costs and unamortized premium (see Note 4). The fair value of the Company’s Senior Notes due 2028, Convertible Notes due 2029 and Senior Notes due 2031 was $706.9 million, $572.8 million and $520.0 million, respectively, at September 30, 2024. These fair values are based on market quotes that represent Level 2 inputs.
There is no active market for the Revolving Credit Facility. The recorded value of the Revolving Credit Facility approximates its fair value because of its floating rate structure based on the SOFR spread, secured interest, and the Company’s borrowing base utilization. The fair value measurement for the Revolving Credit Facility represents Level 2 inputs.
Non-Financial Assets and Liabilities
The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and natural gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligations liability is deemed to use Level 3 inputs. Asset retirement obligations incurred and acquired during the nine months ended September 30, 2024 and 2023 were approximately $2.8 million and $3.6 million, respectively.
The Company issued common stock warrants in January 2022 as a part of the purchase consideration for certain oil and gas properties acquired by the Company. Upon issuance, the Warrants granted holders the right to purchase 1,939,998 shares of the Company’s common stock at an exercise price equal to $28.30 per share (subject to certain adjustments), generally exercisable from April 27, 2022 until January 27, 2029. A portion of the Warrants were surrendered and cancelled in March 2023, and the remaining Warrants were surrendered and cancelled in March 2024, in each case in exchange for shares of common stock. See
Note 6. The fair value of the Warrants consideration was determined by utilizing an Option Pricing Model. These non-recurring fair value measurements are primarily determined using inputs that are observable or can be corroborated by observable market data (Level 2 inputs).
For all transactions accounted for using the business combination method of accounting, the Company accounts for acquisitions of oil and natural gas properties under the acquisition method of accounting. In those instances, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of oil and natural gas properties. The fair value of these properties is measured using a discounted cash flow model that converts future cash flows to a single discounted amount. These assumptions represent Level 3 inputs under the fair value hierarchy. See Note 3 for additional discussion of the Company’s acquisitions of oil and natural gas properties during the nine months ended September 30, 2024 and discussion of the significant inputs to the valuations.
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. There were no transfers of financial assets or liabilities between Level 1, Level 2 or Level 3 inputs for the nine months ended September 30, 2024.
NOTE 10 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT
The Company utilizes various commodity price derivative instruments to (i) reduce the effects of volatility in price changes on the crude oil and natural gas commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending. In addition, from time to time the Company utilizes interest rate swaps to mitigate exposure to changes in interest rates on the Company’s variable-rate indebtedness.
All derivative instruments are recorded in the Company’s condensed balance sheets as either assets or liabilities measured at their fair value (see Note 9). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value are recognized in the Company’s condensed statements of operations as a gain or loss on derivative instruments. Mark-to-market gains and losses represent changes in fair values of derivative instruments that have not been settled. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
The Company has master netting agreements on individual derivative instruments with certain counterparties and therefore the current asset and liability are netted in the balance sheet and the non-current asset and liability are netted in the balance sheet for contracts with these counterparties.
Commodity Derivative Instruments
The following table presents settlements on commodity derivative instruments and unsettled gains and losses on open commodity derivative instruments for the periods presented which is recorded in the revenue section of our condensed financial statements:
Three Months Ended September 30,
Nine Months Ended September 30,
(In thousands)
2024
2023
2024
2023
Cash Received on Settled Derivatives
$
29,709
$
5,164
$
57,721
$
46,099
Non-Cash Mark-to-Market Gain (Loss) on Derivatives
The following table summarizes open commodity derivative positions as of September 30, 2024, for commodity derivatives that were entered into through September 30, 2024, for the settlement period presented:
2024
2025
2026
2027
2028
Oil:
WTI NYMEX - Swaps:
Volume (Bbl)
2,527,109
8,673,162
704,557
—
—
Weighted-Average Price ($/Bbl)
$
74.06
$
74.18
$
68.34
$
—
$
—
WTI NYMEX - Swaptions(1):
Volume (Bbl)
—
4,958,700
3,512,950
4,369,050
640,500
Weighted-Average Price ($/Bbl)
$
—
$
74.68
$
70.42
$
70.54
$
70.00
Argus American Crude WTI Midland to WTI NYMEX - Basis Swaps:
(1)Swaptions are crude oil and natural gas derivative contracts that give counterparties the option to extend certain derivative contracts for additional periods. Call Options are crude oil and natural gas derivative contracts sold by the Company that give counterparties the option to exercise certain derivative contracts. The volumes and prices reflected as Swaptions and Call Options in this table will only be effective if the options are exercised by the applicable counterparties.
Interest Rate Derivative Instruments
At times, the Company uses interest rate swaps to effectively convert a portion of its variable rate indebtedness to fixed rate indebtedness. The settlement of derivative instruments is recognized as a component of interest expense in the condensed statements of operations. The mark-to-market component of the unsettled derivative instruments is recognized in gain (loss) on unsettled interest rate derivatives, net in the condensed statements of operations.
Other Information Regarding Derivative Instruments
The following table sets forth the amounts, on a gross basis, and classification of the Company’s outstanding derivative financial instruments at September 30, 2024 and December 31, 2023, respectively. Certain amounts may be presented on a net basis in the condensed financial statements when such amounts are with the same counterparty and subject to a master netting arrangement.
(In thousands)
Type of Commodity
Balance Sheet Location
September 30, 2024 Estimated Fair Value
December 31, 2023 Estimated Fair Value
Derivative Assets:
Commodity Price Swap Contracts
Current Assets
$
75,244
$
61,323
Commodity Basis Swap Contracts
Current Assets
6,630
4,487
Commodity Price Swaptions Contracts
Current Assets
2,997
—
Commodity Price Collar Contracts
Current Assets
58,762
36,619
Commodity Price Call Option Contracts
Current Assets
1,865
17,964
Commodity Price Put Option Contracts
Current Assets
—
664
Interest Rate Swap Contracts
Current Assets
112
—
Commodity Price Swap Contracts
Noncurrent Assets
16,420
16,621
Commodity Basis Swap Contracts
Noncurrent Assets
13,176
1,874
Commodity Price Swaptions Contracts
Noncurrent Assets
1,007
—
Commodity Price Collar Contracts
Noncurrent Assets
50,184
26,841
Commodity Price Call Option Contracts
Noncurrent Assets
644
3,635
Total Derivative Assets
$
227,042
$
170,029
Derivative Liabilities:
Commodity Price Swap Contracts
Current Liabilities
$
(1,500)
$
(8,079)
Commodity Basis Swap Contracts
Current Liabilities
(5,408)
(6,796)
Commodity Price Swaptions Contracts
Current Liabilities
(8,403)
(1,496)
Commodity Price Collar Contracts
Current Liabilities
(18,740)
(14,370)
Commodity Price Call Option Contracts
Current Liabilities
(11,549)
(31,380)
Interest Rate Swap Contracts
Current Liabilities
(18)
—
Commodity Price Swap Contracts
Noncurrent Liabilities
(1,159)
(2,288)
Commodity Basis Swap Contracts
Noncurrent Liabilities
(3,331)
(8,922)
Commodity Price Swaptions Contracts
Noncurrent Liabilities
(69,518)
(35,896)
Commodity Price Collar Contracts
Noncurrent Liabilities
(40,777)
(18,849)
Commodity Price Call Option Contracts
Noncurrent Liabilities
(64,245)
(78,123)
Interest Rate Swap Contracts
Noncurrent Liabilities
(114)
—
Total Derivative Liabilities
$
(224,761)
$
(206,198)
The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. When the Company has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments these assets and liabilities are netted in the balance sheet. The tables presented below provide reconciliation between the gross assets and liabilities and the amounts reflected in the balance sheet. The amounts presented exclude derivative settlement receivables and payables as of the balance sheet dates.
Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Offsetting of Derivative Assets:
Current Assets
$
145,610
$
(44,813)
$
100,797
Non-Current Assets
81,432
(66,702)
14,730
Total Derivative Assets
$
227,042
$
(111,515)
$
115,527
Offsetting of Derivative Liabilities:
Current Liabilities
$
(45,617)
$
44,813
$
(804)
Non-Current Liabilities
(179,144)
66,702
(112,442)
Total Derivative Liabilities
$
(224,761)
$
111,515
$
(113,246)
Estimated Fair Value at December 31, 2023
(In thousands)
Gross Amounts of Recognized Assets (Liabilities)
Gross Amounts Offset on the Balance Sheet
Net Amounts of Assets (Liabilities) Presented on the Balance Sheet
Offsetting of Derivative Assets:
Current Assets
$
121,057
$
(45,324)
$
75,733
Non-Current Assets
48,971
$
(38,246)
10,725
Total Derivative Assets
$
170,029
$
(83,570)
$
86,459
Offsetting of Derivative Liabilities:
Current Liabilities
$
(62,120)
$
45,324
$
(16,797)
Non-Current Liabilities
(144,077)
38,246
(105,831)
Total Derivative Liabilities
$
(206,198)
$
83,570
$
(122,628)
All of the Company’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDAs”) entered into with parties that are also lenders under the Company’s Revolving Credit Facility. The Company’s obligations under the derivative instruments are secured pursuant to the Revolving Credit Facility, and no additional collateral had been posted by the Company as of September 30, 2024. The ISDAs may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. See Note 9 for the aggregate fair value of all derivative instruments that were in a net liability position at September 30, 2024 and December 31, 2023.
We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords.
From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, indebtedness covenant compliance, capital expenditures, production, cash flow, borrowing base under our Revolving Credit Facility, our intention or ability to pay or increase dividends on our capital stock, and impairment are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future production, sales, market size, collaborations, cash flows, and trends or operating results also constitute such forward-looking statements.
Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following:
•changes in crude oil and natural gas prices, the pace of drilling and completions activity on our current properties and properties pending acquisition;
•infrastructure constraints and related factors affecting our properties;
•cost inflation or supply chain disruptions;
•ongoing legal disputes over, and potential shutdown of, the Dakota Access Pipeline;
•our ability to acquire additional development opportunities, potential or pending acquisition transactions, the projected capital efficiency savings and other operating efficiencies and synergies resulting from our acquisition transactions, integration and benefits of property acquisitions, or the effects of such acquisitions on our company’s cash position and levels of indebtedness;
•changes in our reserves estimates or the value thereof;
•disruption to our company’s business due to acquisitions and other significant transactions;
•general economic or industry conditions, nationally and/or in the communities in which our company conducts business;
•changes in the interest rate environment, legislation or regulatory requirements;
•conditions of the securities markets;
•risks associated with our Convertible Notes, including the potential impact that the Convertible Notes may have on our financial position and liquidity, potential dilution, and that provisions of the Convertible Notes could delay or prevent a beneficial takeover of our company;
•the potential impact of the capped call transactions undertaken in tandem with the Convertible Notes issuance, including counterparty risk;
•increasing attention to environmental, social and governance matters;
•our ability to consummate any pending acquisition transactions;
•our ability to raise or access capital;
•cyber-incidents could have a material adverse effect on our business, financial condition or results of operations;
•changes in accounting principles, policies or guidelines;
•potential impacts following the result of the presidential election in the United States;
•events beyond our control, including a global or domestic health crisis, acts of terrorism, political or economic instability or armed conflict in oil and gas producing regions; and
•other economic, competitive, governmental, regulatory and technical factors affecting our operations, products and prices.
We have based any forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results actually achieved may differ materially from expected results described in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in the section entitled “Item 1A. Risk Factors” and other sections of our Annual Report
on Form 10-K for the fiscal year ended December 31, 2023, as updated by subsequent reports we file with the SEC (including this report), which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our company does not undertake, and specifically disclaims, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.
Overview
Our primary strategy is to invest in non-operated minority working and mineral interests in oil and gas properties, with a core area of focus in the premier basins within the United States. Using this strategy, we had participated in 10,445 gross (1,049.8 net) producing wells as of September 30, 2024. As of September 30, 2024, we had leased approximately 275,514 net acres, of which approximately 85% were developed and all were located in the United States.
We have grown and diversified our business significantly over the last several years through acquisitions of oil and gas properties. See Note 3 to our condensed financial statements for information regarding our recent acquisition activity.
Our average daily production in the third quarter of 2024 was approximately 121,815 Boe per day, of which approximately 58% was oil. This was a 19% increase in production compared to the third quarter of 2023, primarily due to production attributable to recent acquisitions and new wells added to production. During the three months ended September 30, 2024, we added 9.5 net wells to production.
Our weighted average percentage of production volumes by basin for the three months ended September 30, 2024 and 2023 were as follows:
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
Williston
Permian
Appalachian
Total
Williston
Permian
Appalachian
Total
Oil (Bbl)
48
%
51
%
1
%
100
%
55
%
45
%
—
%
100
%
Natural Gas (Mcf)
29
%
40
%
31
%
100
%
37
%
36
%
27
%
100
%
Total (Boe)
40
%
46
%
14
%
100
%
48
%
42
%
10
%
100
%
Source of Our Revenues
We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.
Principal Components of Our Cost Structure
•Commodity price differentials. The price differential between our well head price for oil and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries. The price differential between our well head price for natural gas and NGLs and the NYMEX Henry Hub benchmark price is primarily driven by gathering and transportation costs.
•Gain (loss) on commodity derivatives, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period end.
•Production expenses. Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.
•Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing
authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.
•Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with our development and acquisition efforts and allocate these costs to each unit of production using the units-of-production method. Accretion expense relates to the passage of time of our asset retirement obligations.
•General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance.
•Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We capitalize a portion of the interest paid on applicable borrowings into our unproved cost pool. We include interest expense that is not capitalized into the unproved cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense.
•Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, a non-cash impairment expense is required. The Company did not have any ceiling test impairment for the three and nine months ended September 30, 2024 and 2023. However, if lower average monthly prices continue to decline in future months, the present value of the Company’s future net revenues could decline significantly, which could trigger the need for the Company to record a non-cash ceiling test impairment of its oil and gas property costs in future periods.
•Income tax expense. Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
Selected Factors That Affect Our Operating Results
Our revenues, cash flows from operations and future growth depend substantially upon:
•the timing and success of drilling and production activities by our operating partners;
•the prices and the supply and demand for oil, natural gas and NGLs;
•the quantity of oil and natural gas production from the wells in which we participate;
•changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices;
•our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and
•the level of our operating expenses.
In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Permian, Appalachian and, following the closing of the XCL Acquisition in October 2024 (see Note 3 to our condensed financial statements), Uinta Basins subjects our operating results to factors specific to these regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during
the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions.
The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price. The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX benchmark price. Thus, our operating results are also affected by changes in the price differentials between the applicable benchmark and the sales prices we receive for our production. Our oil price differential to the NYMEX benchmark price during the third quarter of 2024 was $3.45 per barrel, as compared to $2.84 per barrel in the third quarter of 2023. Our net realized gas price in the third quarter of 2024 was $1.60 per Mcf, representing 72% realization relative to average Henry Hub pricing, compared to a net realized gas price of $2.19 per Mcf in the third quarter of 2023, which represented 82% realization relative to average Henry Hub pricing. Fluctuations in our oil and gas price realizations are due to several factors such as pricing by basin, gathering and transportation costs, transportation method, takeaway capacity relative to production levels, regional storage capacity, seasonal refinery maintenance temporarily depressing demand, and in the case of gas realizations, the price of NGLs.
Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity. Generally, higher commodity prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower commodity prices have generally had the opposite effect. In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant. Since 2021, we have observed inflationary pressures on drilling and other operating costs due to various factors, such as higher commodity prices, labor shortages, supply chain disruptions and other factors. During the first nine months of 2024 and 2023, the weighted average gross authorization for expenditure (or AFE) cost for wells we elected to participate in was $9.1 million and $9.4 million, respectively. The decrease is due in part to a decline in Permian lateral lengths relative to the prior year.
Market Conditions
The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can significantly impact oil prices. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.
Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the three and nine months ended September 30, 2024 and 2023.
We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production. For a summary as of September 30, 2024, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Part I, Item 3 below. See also Note 10 to our condensed financial statements.
Results of Operations for the Three Months Ended September 30, 2024 and September 30, 2023
The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.
Three Months Ended September 30,
2024
2023
% Change
Net Production (in thousands):
Oil (MBbl)
6,524
5,848
12
%
Natural Gas (MMcf)
28,098
21,397
31
%
Total (MBoe)
11,207
9,414
19
%
Net Sales (in thousands):
Oil Sales
$
468,547
$
464,793
1
%
Natural Gas and NGL Sales
44,994
46,858
(4)
%
Gain on Settled Commodity Derivatives
29,709
5,164
475
%
Gain (Loss) on Unsettled Commodity Derivatives
208,441
(204,712)
Other Revenue
1,947
1,870
4
%
Total Revenues
753,638
313,973
140
%
Average Sales Prices:
Oil (per Bbl)
$
71.82
$
79.48
(10)
%
Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)
0.20
(2.58)
Oil Net of Settled Oil Derivatives (per Bbl)
72.02
76.90
(6)
%
Natural Gas and NGLs (per Mcf)
$
1.60
$
2.19
(27)
%
Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf)
1.01
0.95
6
%
Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf)
2.61
3.14
(17)
%
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives
$
45.82
$
54.35
(16)
%
Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe)
2.65
0.55
382
%
Realized Price on a Boe Basis Including Settled Commodity Derivatives
48.47
54.90
(12)
%
Operating Expenses (in thousands):
Production Expenses
$
106,902
$
82,506
30
%
Production Taxes
14,671
$
42,158
(65)
%
General and Administrative Expenses
10,005
$
11,846
(16)
%
Depletion, Depreciation, Amortization and Accretion
185,657
$
133,791
39
%
Other Expense
2,463
1,235
100
%
Costs and Expenses (per Boe):
Production Expenses
$
9.54
$
8.76
9
%
Production Taxes
1.31
4.48
(71)
%
General and Administrative Expenses
0.89
1.26
(29)
%
Depletion, Depreciation, Amortization and Accretion
In the third quarter of 2024, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $513.5 million, compared to $511.7 million in the third quarter of 2023. The slight increase was driven by a 19% increase in production volumes, partially offset by a 16% decrease in realized prices.
We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. Acquisitions were a significant driver of our 19% increase in production levels in the third quarter of 2024 compared to the same period of 2023.
Commodity Derivative Instruments
We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our net result from commodity derivatives trade was a gain of $238.2 million in the third quarter of 2024, compared to a loss of $199.5 million in the third quarter of 2023. Net gain or loss on commodity derivatives is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.
For the third quarter of 2024, we realized a gain on settled commodity derivatives of $29.7 million, compared to a gain of $5.2 million in the third quarter of 2023. The increased gain on settled derivatives was primarily due to lower average oil NYMEX pricing in the third quarter of 2024 compared to the same period of 2023.
For the third quarter of 2024, we realized a gain on our unsettled commodity derivative of $208.4 million, compared to a loss of $204.7 million in the third quarter of 2023. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives. Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. At September 30, 2024, all of our derivative contracts are recorded at their fair value, which was a net asset of $2.3 million, a change of $38.5 million from the $36.2 million net liability recorded as of December 31, 2023. The increase in asset at September 30, 2024 as compared to December 31, 2023 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2023. Our open commodity derivative contracts are summarized in “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
Production Expenses
Production expenses were $106.9 million in the third quarter of 2024, compared to $82.5 million in the third quarter of 2023. On a per unit basis, production expenses were $9.54 per Boe in the third quarter of 2024 compared to $8.76 per Boe in the third quarter of 2023. The higher production expenses per Boe were driven by higher salt water disposal costs in the third quarter of 2024 compared to the third quarter of 2023. On an absolute dollar basis, the increase in our production expenses in the third quarter of 2024 compared to the third quarter of 2023 was primarily due to a 19% increase in production volumes and a 14% increase in the total number of net producing wells.
Production Taxes
We pay production taxes based on realized oil and natural gas sales. Production taxes were $14.7 million in the third quarter of 2024, compared to $42.2 million in the third quarter of 2023. As a percentage of oil and natural gas sales, our production taxes were 2.9% and 8.2% in the third quarter of 2024 and 2023, respectively. The fluctuation in our production taxes and average production tax rates from year to year was primarily due to certain out-of-period adjustments made to production taxes, as discussed under the heading “Out-of-Period Adjustments” in Note 2 to the condensed financial statements.
General and administrative expenses were $10.0 million in the third quarter of 2024 compared to $11.8 million in the third quarter of 2023. The decrease was driven in part by a $5.3 million decrease in acquisition-related costs, partially offset by a $3.6 million increase in total compensation expense in the third quarter of 2024 as compared to the third quarter of 2023, driven in part by an increase in the Company’s workforce commensurate with the Company’s growth.
Depletion, Depreciation, Amortization and Accretion
Depletion, depreciation, amortization and accretion (“DD&A”) was $185.7 million in the third quarter of 2024, compared to $133.8 million in the third quarter of 2023. Depletion expense, the largest component of DD&A, increased by $51.7 million in the third quarter of 2024 compared to the third quarter of 2023. The aggregate increase in depletion expense was driven by a 19% increase in production levels and a 17% increase in the depletion rate per Boe. On a per unit basis, depletion expense was $16.47 per Boe in the third quarter of 2024 compared to $14.11 per Boe in the third quarter of 2023. The higher depletion rate per Boe was primarily driven by a significant increase to our depletable base, due to the closing of several larger acquisitions in 2023 and 2024 (see Note 3 to our condensed financial statements). Depreciation, amortization and accretion was $1.1 million and $1.0 million in the third quarter of 2024 and 2023, respectively. The following table summarizes DD&A expense per Boe for the third quarter of 2024 and 2023:
Three Months Ended September 30,
2024
2023
$ Change
% Change
Depletion
$
16.47
$
14.11
$
2.36
17
%
Depreciation, Amortization and Accretion
0.10
0.10
—
—
%
Total DD&A Expense
$
16.57
$
14.21
$
2.36
17
%
Interest Expense
Interest expense, net of capitalized interest, was $36.8 million in the third quarter of 2024 compared to $37.0 million in the third quarter of 2023. The slight decrease was primarily due to lower levels of average outstanding borrowings on our revolving credit facility in the third quarter of 2024 compared to the third quarter of 2023.
Income Tax
During the third quarter of 2024, we recorded income tax expense of $98.8 million. During the third quarter of 2023, we recorded an income tax benefit of $20.7 million, driven by the release of a valuation allowance on certain deferred taxes.
Results of Operations for the Nine Months Ended September 30, 2024 and September 30, 2023
The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.
Nine Months Ended September 30,
2024
2023
% Change
Net Production (in thousands):
Oil (MBbl)
19,249
15,677
23
%
Natural Gas (MMcf)
84,310
59,230
42
%
Total (MBoe)
33,300
25,549
30
%
Net Sales (in thousands):
Oil Sales
$
1,422,916
$
1,174,007
21
%
Natural Gas and NGL Sales
183,691
180,370
2
%
Gain on Settled Commodity Derivatives
57,721
46,099
25
%
Gain (Loss) on Unsettled Commodity Derivatives
38,470
(34,222)
Other Revenue
7,953
6,488
23
%
Total Revenues
1,710,751
1,372,742
25
%
Average Sales Prices:
Oil (per Bbl)
$
73.92
$
74.89
(1)
%
Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl)
(0.97)
(0.92)
Oil Net of Settled Oil Derivatives (per Bbl)
72.95
73.97
(1)
%
Natural Gas and NGLs (per Mcf)
$
2.18
$
3.05
(29)
%
Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf)
0.91
1.02
(11)
%
Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf)
3.09
4.07
(24)
%
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives
$
48.25
$
53.01
(9)
%
Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe)
1.73
1.80
(4)
%
Realized Price on a Boe Basis Including Settled Commodity Derivatives
49.98
54.81
(9)
%
Operating Expenses (in thousands):
Production Expenses
$
313,209
$
244,944
28
%
Production Taxes
114,470
114,215
—
%
General and Administrative Expenses
34,936
37,248
(6)
%
Depletion, Depreciation, Amortization and Accretion
536,227
334,836
60
%
Other Expense
6,713
3,681
82
%
Costs and Expenses (per Boe):
Production Expenses
$
9.41
$
9.59
(2)
%
Production Taxes
3.44
4.47
(23)
%
General and Administrative Expenses
1.05
1.46
(28)
%
Depletion, Depreciation, Amortization and Accretion
In the first nine months of 2024, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, was $1,606.6 million, compared to $1,354.4 million in the first nine months of 2023. This 19% increase was driven by a 30% increase in production volumes, partially offset by a 9% decrease in realized prices. The lower average realized price in the first nine months of 2024 as compared to the same period in 2023 was driven by a $0.97 per bbl decrease in realized oil prices, excluding the effect of settled commodity derivatives. Oil price differential during the first nine months of 2024 was $3.69 per barrel, as compared to $2.44 per barrel in the first nine months of 2023.
We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells. Acquisitions were a significant driver of our 30% increase in production levels in the first nine months of 2024 compared to the same period of 2023.
Commodity Derivative Instruments
We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our net gain on commodity derivatives was $96.2 million in the first nine months of 2024, compared to a net gain of $11.9 million in the first nine months of 2023. Net gain on commodity derivative is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.
For the first nine months of 2024, we realized a gain on settled commodity derivatives of $57.7 million, compared to a gain of $46.1 million in the first nine months of 2023. The increase in the gain on settled commodity derivatives was primarily due to lower average NYMEX gas price and increased settled commodity volumes in the first nine months of 2024 compared to the same period of 2023.
For the first nine months of 2024, we realized a gain on unsettled commodity derivative of $38.5 million, compared to a loss of $34.2 million in the first nine months of 2023. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as gains and losses from unsettled derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our commodity derivatives. Any gains on our unsettled commodity derivatives are expected to be offset by lower wellhead revenues in the future, while any losses are expected to be offset by higher future wellhead revenues based on the value at the settlement date. At September 30, 2024, all of our derivative contracts are recorded at their fair value, which was a net asset of $2.3 million, a change of $38.5 million from the $36.2 million net liability recorded as of December 31, 2023. The increase in asset at September 30, 2024 as compared to December 31, 2023 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2023. Our open commodity derivative contracts are summarized in “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
Production Expenses
Production expenses were $313.2 million in the first nine months of 2024, compared to $244.9 million in the first nine months of 2023. On a per unit basis, production expenses were $9.41 per Boe in the first nine months of 2024 compared to $9.59 per Boe in the first nine months of 2023. The lower production expenses per Boe was driven by a decrease in firm transport expenses in the first nine months of 2024 compared to the first nine months of 2023. On an absolute dollar basis, the increase in our production expenses in the first nine months of 2024 compared to the first nine months of 2023 was primarily due to a 30% increase in production volumes and a 14% increase in the total number of net producing wells.
Production Taxes
We pay production taxes based on realized oil and natural gas sales. Production taxes were $114.5 million in the first nine months of 2024, compared to $114.2 million in the first nine months of 2023. As a percentage of oil and natural gas sales, our production taxes were 7.1% and 8.4% in the first nine months of 2024 and 2023, respectively. The fluctuation in our average production tax rates from year to year was primarily due to certain out-of-period adjustments made to production taxes, as discussed under the heading “Out-of-Period Adjustments” in Note 2 to the condensed financial statements.
General and administrative expenses were $34.9 million in the first nine months of 2024 compared to $37.2 million in the first nine months of 2023. The decrease was primarily due to a $9.5 million decrease in acquisition-related costs in the first nine months of 2024 as compared to the first nine months of 2023, partially offset by a $6.4 million increase in total compensation expense.
Depletion, Depreciation, Amortization and Accretion
DD&A was $536.2 million in the first nine months of 2024, compared to $334.8 million in the first nine months of 2023. Depletion expense, the largest component of DD&A, increased by $200.9 million in the first nine months of 2024 compared to the first nine months of 2023. The aggregate increase in depletion expense was driven by a 30% increase in production levels and a 23% increase in the depletion rate per Boe. On a per unit basis, depletion expense was $16.01 per Boe in the first nine months of 2024 compared to $13.00 per Boe in the first nine months of 2023. The higher depletion rate per Boe was primarily driven by a significant increase to our depletable base, due to the closing of several larger acquisitions in 2023 and 2024 (see Note 3 to our condensed financial statements). Depreciation, amortization and accretion was $3.2 million and $2.7 million in the first nine months of 2024 and 2023, respectively. The following table summarizes DD&A expense per Boe for the first nine months of 2024 and 2023:
Nine Months Ended September 30,
2024
2023
$ Change
% Change
Depletion
$
16.01
$
13.00
$
3.01
23
%
Depreciation, Amortization and Accretion
0.09
0.11
(0.02)
(18)
%
Total DD&A Expense
$
16.10
$
13.11
$
2.99
23
%
Interest Expense
Interest expense, net of capitalized interest, was $112.5 million in the first nine months of 2024 compared to $99.2 million in the first nine months of 2023. The increase was primarily due to higher levels of debt outstanding during the first nine months of 2024 compared to the first nine months of 2023. Additionally, higher interest rates on our floating rate debt contributed to higher interest expense in the first nine months of 2024 compared to the first nine months of 2023.
Income Tax
During the first nine months of 2024, we recorded income tax expense of $144.4 million which equated to an effective tax rate of 24.3%. During the first nine months of 2023, we recorded income tax expense of $19.0 million which equated to an effective tax rate of 3.4%. The difference was due primarily to the release of our valuation allowance during the third quarter of 2023.
On August 16, 2022, the U.S. enacted the Inflation Reduction Act which included the adoption of the Corporate Alternative Minimum Tax, which is based on financial statement book income of large corporations. In 2024, the Company is not subject to the Corporate Alternative Minimum Tax.
Liquidity and Capital Resources
Overview
Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, proceeds from equity and debt financings, credit facility borrowings and cash settlements of commodity derivative instruments. Our primary uses of capital have been for the acquisition, development and operation of our oil and natural gas properties, cash settlements of commodity derivative instruments and for stockholder returns. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.
In January 2024, we completed the Delaware Acquisition for total cash consideration of $147.8 million (see Note 3 to our condensed financial statements). In September 2024, we completed the Point Acquisition for total cash consideration of approximately $197.8 million (see Note 3 to our condensed financial statements). Subsequent to September 30, 2024, in
October 2024, we completed the XCL Acquisition for total cash consideration of approximately $511.3 million, which included a $25.5 million cash deposit that we previously paid at signing in June 2024 (see Note 3 to our condensed financial statements).
During the nine months ended September 30, 2024, we repurchased and retired 1,841,733 shares of our common stock for total consideration of $69.3 million, or an average price of $37.64 per share.
As of September 30, 2024, we had outstanding total debt of $1,980.1 million consisting of $275.0 million of borrowings under our Revolving Credit Facility, $705.1 million aggregate principal amount of our Senior Notes due 2028, $500.0 million aggregate principal amount of our Senior Notes due 2031, and $500.0 million aggregate principal amount of our Convertible Notes.
As of September 30, 2024, we had total liquidity of $1.3 billion, consisting of $1.2 billion of committed borrowing availability under the Revolving Credit Facility and $34.4 million of cash on hand.
One of the primary sources of variability in our cash flows from operating activities is commodity price volatility. Oil accounted for 91% and 91% of our total oil and gas sales in the third quarter of 2024 and 2023, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices. We seek to maintain a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the nine months ended September 30, 2024, we hedged approximately 74% of our crude oil production and approximately 62% of our natural gas production. For a summary as of September 30, 2024, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk” in Part I, Item 3 below.
With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months and, based on current expectations, for the foreseeable future. However, we may seek additional access to capital and liquidity. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.
Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility. Our capital expenditures could be curtailed if our cash flows decline from expected levels. Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.
Working Capital
Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, collection of receivables, expenditures related to our development and production operations and the impact of our outstanding derivative instruments.
At September 30, 2024, we had a working capital surplus of $98.6 million, compared to a surplus of $123.6 million at December 31, 2023. Current assets increased by $9.5 million and current liabilities increased by $34.5 million at September 30, 2024, compared to December 31, 2023.
Cash Flows
Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 36 months. Our cash flows for the nine months ended September 30, 2024 and 2023 are presented below:
Net Cash Provided by (Used for) Financing Activities
(80,108)
653,668
Net Increase (Decrease) in Cash
$
26,161
$
10,424
Cash Flows from Operating Activities
Net cash provided by operating activities for the nine months ended September 30, 2024 was $1,118.4 million, compared to $841.0 million in the same period of the prior year. This increase was due to significantly higher production volumes, offset by lower realized natural gas prices (including the effect of settled derivatives) and higher operating costs. Net cash provided by operating activities is affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital and other items (as reflected in our statements of cash flows) in the nine months ended September 30, 2024 was a surplus of $14.7 million compared to a deficit of $82.6 million in the same period of the prior year.
Cash Flows from Investing Activities
Cash flows used in investing activities during the nine months ended September 30, 2024 and 2023 were $1,012.1 million and $1,484.2 million, respectively. The decrease in cash used in investing activities for the first nine months of 2024 as compared to the same period of 2023 was attributable to a $471.6 million decrease in our capital expenditures for oil and natural gas properties spending. Additionally, the amount of capital expenditures included in accounts payable (and thus not included in cash flows from investing activities) was $232.6 million and $281.5 million at September 30, 2024 and 2023, respectively.
Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity. For instance, during the nine months ended September 30, 2024, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $1,082.5 million, while the actual cash spend in this regard amounted to $1,012.0 million.
Development and acquisition activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and returns. Our cash spend for development and acquisition activities for the nine months ended September 30, 2024 and 2023 are summarized in the following table:
Nine Months Ended September 30,
(In thousands, unaudited)
2024
2023
Drilling and Development Capital Expenditures
$
630,988
$
484,322
Acquisition of Oil and Natural Gas Properties
378,654
996,650
Other Capital Expenditures
2,361
2,667
Total
$
1,012,003
$
1,483,639
Cash Flows from Financing Activities
Net cash used for financing activities was $80.1 million during the nine months ended September 30, 2024, compared to net cash provided by financing activities of $653.7 million during the nine months ended September 30, 2023. For the nine months ended September 30, 2024, cash used for financing activities was primarily related to $120.2 million of common stock dividend payments and $69.3 million in repurchases of common stock, which was partially offset by $114.0 million of net advances under our Revolving Credit Facility. For the nine months ended September 30, 2023, cash provided by financing activities was primarily related to the issuance of the Senior Notes due 2031 of $492.8 million, the issuance of common stock of $224.7 million, and $65.0 million of net advances under our Revolving Credit Facility, partially offset by $88.7 million of common stock dividend payments, $18.4 million in repurchases of our Senior Notes due 2028, and $8.0 million in repurchases of common stock.
We have entered into a Revolving Credit Facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto. The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and gas properties. As of September 30, 2024, the Revolving Credit Facility had a borrowing base of $1.8 billion and an elected commitment amount of $1.5 billion, and we had $275.0 million in borrowings outstanding under the facility, leaving $1.2 billion in available committed borrowing capacity. See Note 4 to our condensed financial statements for further details regarding the Revolving Credit Facility.
Senior Notes due 2028
As of September 30, 2024, we had outstanding $705.1 million aggregate principal amount of our Senior Notes due 2028. See Note 4 to our condensed financial statements for further details regarding the Senior Notes due 2028.
Senior Notes due 2031
As of September 30, 2024, we had outstanding $500.0 million aggregate principal amount of our Senior Notes due 2031. See Note 4 to our condensed financial statements for further details regarding the Senior Notes due 2031.
Convertible Notes due 2029
As of September 30, 2024, we had outstanding $500.0 million aggregate principal amount of our Convertible Notes. See Note 4 to our condensed financial statements for further details regarding the Convertible Notes.
Effects of Inflation and Pricing
The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Based on current conditions and expectations, we are not budgeting for any significant change in per well drilling and completion and other associated costs in 2024 compared to 2023.
Contractual Obligations and Commitments
Please see our disclosure of contractual obligations and commitments as of December 31, 2023, included in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
Critical Accounting Estimates
Critical accounting estimates are those estimates made in accordance with GAAP that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operations. Our critical accounting estimates include impairment testing of natural gas and crude oil production properties, derivative instruments and hedging activity, and income taxes. There were no material changes in our critical accounting estimates from those reported in our Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
A description of our critical accounting policies, including estimates, was provided in Note 2 to our financial statements provided in Part II, Item 8 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Our quantitative and qualitative disclosures about market risk for changes in commodity prices and interest rates are included in Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023 and, except as set forth below, have not materially changed since that report was filed.
The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand and other factors. Historically, the markets for oil and natural gas have been volatile, and we believe these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenue generally would have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil that also increase and decrease along with oil prices.
We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to commodity price volatility. All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations rather than as a component of other comprehensive income or other income (expense).
We generally use derivatives to economically hedge a significant, but varying portion of our anticipated future production. Any payments due to counterparties under our derivative contracts are funded by proceeds received from the sale of our production. Production receipts, however, lag payments to the counterparties. Any interim cash needs are funded by cash from operations or borrowings under our Revolving Credit Facility.
The following table summarizes our open crude oil derivative contracts as of September 30, 2024, by fiscal quarter.
Crude Oil Contracts
Swaps(1)
Collars
Contract Period
Volume (Bbls)
Weighted Average Price ($/Bbl)
Volume Ceiling (Bbls)
Volume Floor (Bbls)
Weighted Average Ceiling Price ($/Bbl)
Weighted Average Floor Price ($/Bbl)
2024:
Q4
2,527,109
$
74.06
2,195,749
1,998,800
$
81.32
$
71.58
2025:
Q1
2,861,199
$
74.84
2,303,286
1,889,849
$
78.25
$
69.68
Q2
2,468,158
74.52
2,047,671
1,655,233
77.58
69.55
Q3
1,693,969
73.47
1,844,994
1,449,970
77.57
69.26
Q4
1,649,836
73.18
1,818,511
1,423,487
77.73
69.26
2026:
Q1
173,726
$
68.50
1,055,726
714,289
$
74.46
$
66.44
Q2
175,657
68.39
1,067,457
722,227
74.46
66.44
Q3
177,587
68.29
1,079,187
730,163
74.46
66.44
Q4
177,587
68.16
1,079,187
730,163
74.46
66.44
_____________
(1)This table does not include volumes subject to swaptions and call options, which are crude oil derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties. This table also does not include basis swaps. See Note 10 to our condensed financial statements for further details regarding our commodity derivatives, including the swaptions and call options that are not included in the foregoing table.
The following table summarizes our open natural gas derivative contracts as of September 30, 2024, by fiscal quarter.
Natural Gas Contracts
Swaps(1)
Collars
Contract Period
Volume (MMBTU)
Weighted Average Price ($/MMBTU)
Volume Ceiling (MMBTU)
Volume Floor (MMBTU)
Weighted Average Ceiling Price ($/MMBTU)
Weighted Average Floor Price ($/MMBTU)
2024:
Q4
7,097,909
$
3.46
5,490,000
5,490,000
$
4.31
$
3.04
2025:
Q1
4,810,000
$
3.58
9,880,734
9,880,734
$
5.19
$
3.12
Q2
2,420,000
3.55
8,864,216
8,864,216
4.81
3.13
Q3
1,840,000
3.55
8,396,781
8,396,781
4.81
3.13
Q4
1,840,000
3.55
8,428,797
8,428,797
4.90
3.12
2026:
Q1
1,350,000
$
3.74
5,893,735
5,893,735
$
5.06
$
3.09
Q2
1,365,000
3.74
5,959,220
5,959,220
5.06
3.09
Q3
1,380,000
3.74
6,024,706
6,024,706
5.06
3.09
Q4
1,380,000
3.74
6,024,706
6,024,706
5.06
3.09
2027:
Q1
—
$
—
900,000
900,000
$
3.83
$
3.00
Q2
—
—
910,000
910,000
3.83
3.00
Q3
—
—
920,000
920,000
3.83
3.00
Q4
—
—
920,000
920,000
3.83
3.00
_____________
(1)This table does not include volumes subject to swaptions and call options, which are natural gas derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties. This table also does not include basis swaps. See Note 10 to our condensed financial statements for further details regarding our commodity derivatives, including the call options and basis swaps that are not included in the foregoing table.
Interest Rate Risk
Our long-term debt as of September 30, 2024 was comprised of borrowings that contain fixed and floating interest rates. Our Senior Notes due 2028, Senior Notes due 2031, and Convertible Notes bear cash interest at fixed rates. Our Revolving Credit Facility interest rate is a floating rate option that is designated by us within the parameters established by the underlying agreement (see Note 4 to our condensed financial statements).
From time to time, the Company may use interest rate swaps to effectively convert a portion of its variable rate indebtedness to fixed rate indebtedness. The following table summarizes our open interest rate derivative contracts as of September 30, 2024.
Changes in interest rates can impact results of operations and cash flows. A 1% increase in short-term interest rates on our floating-rate debt outstanding at September 30, 2024 would cost us approximately $2.8 million in additional annual interest expense.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
We maintain a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934, as amended (“Exchange Act”), reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.
As of September 30, 2024, our management, including our principal executive officer and principal financial officer, had evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) pursuant to Rule 13a-15(b) under the Exchange Act. Based upon and as of the date of the evaluation, our principal executive officer and principal financial officer concluded that information required to be disclosed is recorded, processed, summarized and reported within the specified periods and is accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow for timely decisions regarding required disclosure of material information required to be included in our periodic SEC reports. Based on the foregoing, our management determined that our disclosure controls and procedures were effective as of September 30, 2024.
Changes in Internal Control over Financial Reporting
No change in our Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarter ended September 30, 2024, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Our Company is subject from time to time to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.
Item 1A. Risk Factors.
There have been no material changes to the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K filed with the SEC for the period ended December 31, 2023.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Unregistered Sales of Equity Securities and Use of Proceeds
None.
Issuer Purchases of Equity Securities
The table below sets forth the information with respect to purchases made by or on behalf of the Company, or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act) of our common stock during the quarter ended September 30, 2024.
Period
Total Number of Shares
Purchased
Average Price Paid Per Share
Total Number of Shares
Purchased as Part of Publicly
Announced Plans or Programs
Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(1)
Month #1
July 1, 2024 to July 22, 2024
—
$
—
—
$32.6 million
July 23, 2024 to July 31, 2024
—
$
—
—
$150.0 million
Month #2
August 1, 2024 to August 31, 2024
266,464
$
37.55
266,464
$140.0 million
Month #3
September 1, 2024 to September 30, 2024
130,837
$
34.01
130,837
$135.5 million
Total
397,301
$
36.38
397,301
$135.5 million
______________
(1)On May 3, 2022, the Company’s board of directors approved and the Company promptly announced a stock repurchase program to acquire up to $150 million of shares of our outstanding common stock. On July 23, 2024, the Company’s board of directors terminated the prior stock repurchase program, and approved and promptly announced a new stock repurchase program to acquire up to $150 million of the Company’s outstanding common stock. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.
(c) During the quarter ended September 30, 2024, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.
Form of August 2024 Performance-Based Restricted Stock Unit Award Agreement (Compound Annualized TSR) under the Northern Oil and Gas, Inc. Amended and Restated 2018 Equity Incentive Plan
Form of August 2024 Performance-Based Restricted Stock Unit Award Agreement (Relative TSR) under the Northern Oil and Gas, Inc. Amended and Restated 2018 Equity Incentive Plan
Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
The cover page from Northern Oil and Gas, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2024, formatted in Inline XBRL and contained in Exhibit 101
Filed herewith
* Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
NORTHERN OIL AND GAS, INC.
Date:
November 6, 2024
By:
/s/ Nicholas O’Grady
Nicholas O’Grady, Chief Executive Officer (on behalf of Registrant)
Date:
November 6, 2024
By:
/s/ Chad Allen
Chad Allen, Chief Financial Officer and principal financial and accounting officer (on behalf of Registrant)