Mach Natural Resources LP: Form 10-Q for the period ended Jun 30, 2026

Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company’s operating results. The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and related notes included in Part I, Item I of this Quarterly Report and also with “Risk Factors” included in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2025. The following information updates the discussion of our financial condition provided in our previous filings and analyzes the changes in the results of operations for the three and six months ended June 30, 2026 and 2025.

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance, which may affect our future operating results and financial position. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Actual results and the timing of the events could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic, inflationary and competitive conditions, drilling results, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Quarterly Report, particularly under “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

We are an independent upstream oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Anadarko Basin region of Western Oklahoma, Southern Kansas and the panhandle of Texas; the San Juan Basin region of New Mexico and Colorado; and the Permian Basin region of West Texas.

Within our operating areas, our assets are prospective for multiple formations, most notably the Oswego, Woodford and Mississippian, Mancos and Fruitland formations. Our experience across these formations allows us to generate significant cash available for distribution from these low declining assets in a variety of commodity price environments. We also own an extensive portfolio of complementary midstream assets that are integrated with our upstream operations. These assets include gathering systems, processing plants and water infrastructure. Our midstream assets enhance the value of our properties by allowing us to optimize pricing, increase flow assurance and eliminate third-party costs and inefficiencies. In addition, our owned midstream systems generate third-party revenue.

Market Outlook

Our financial results depend on many factors, particularly commodity prices and our ability to find, develop and market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand. The oil and natural gas industry is cyclical and commodity prices are highly volatile and we expect continued and increased pricing volatility in the crude oil and natural gas markets. Regional and worldwide economic activity, including any economic downturn or recession that has occurred or may occur in the future, extreme weather conditions and other substantially variable factors, influence market conditions for these products. Between January 1, 2025 and June 30, 2026, NYMEX WTI prices for crude oil ranged from $55.27 to $112.95 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from $2.52 to $7.46 per MMBtu. The war in Ukraine and conflict in the Middle East, uncertainty regarding interest rates, global supply chain disruptions, the potential for significant new tariffs, OPEC+’s decision to increase production in May and July 2025, and concerns about a potential economic downturn or recession have contributed to recent economic and pricing volatility and may continue to impact pricing throughout 2025.

Between 2022 and 2024, the Federal Reserve raised the target range for the federal funds rate in an effort to curb inflation. In September 2025, October 2025 and December 2025, the Federal Reserve lowered the target range for the federal funds rate to its current range of 3.50% to 3.75% in light of the reduced inflation. In June 2026, inflation, as measured by the consumer price index, was 3.5%. We cannot predict the future inflation rate but to the extent we experience high inflation, we may see cost increases in our operations, including costs for drill rigs, workover rigs, tubulars and other well equipment, as well as increased labor costs. We continue to evaluate actions to mitigate supply chain and inflationary pressures and work closely with other suppliers and contractors to ensure availability of supplies on site, especially fuel, steel and chemical supplies which are critical to many of our operations. However, these mitigation efforts may not succeed or may be insufficient. Further, if we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our operations, including the following sources of our revenue, principal components of our cost structure and other financial metrics:

• net production volumes;
• realized prices on the sale of oil, natural gas and NGLs;
• lease operating expense;
• Adjusted EBITDA; and
• cash available for distribution.

Factors Affecting the Comparability of Our Future Results of Operations to Our Historical Results of Operations

Our future results of operations may not be comparable to our historical results of operations for the periods presented, primarily for the reasons described below.

Acquisitions

We have completed four acquisitions since the beginning of 2025, most notably the IKAV and Sabinal Acquisitions (as defined in Note 3) that closed in September 2025. These acquisitions are reflected in our results of operations as of and after the date of completion for each such acquisition. As a result, periods prior to each such acquisition will not contain the results of such acquired assets which will affect the comparability of our results of operations for certain historical periods. We may continue to grow our operations through acquisitions when economical, including by funding such acquisitions under our New Credit Agreement.

Results of Operations

Three Months Ended June 30, 2026 Compared to the Three Months Ended June 30, 2025

Revenue

The following table provides the components of our revenue, net of transportation and marketing costs, for the periods indicated, as well as each period’s respective average realized prices and net production volumes. Some totals and changes throughout the below section may not sum or recalculate due to rounding.

($ in thousands)

Revenue and Other Operating Income

Oil, natural gas and NGL sales

Revenues from oil, natural gas and NGL sales increased $147.4 million, or 67% for the three-month period ended June 30, 2026, as compared to the three-month period ended June 30, 2025. This increase was primarily related to a 78% production increase, which resulted in increased oil, natural gas and NGL sales of $100.2 million. Additionally, the increase in oil and NGL prices resulted in an increase in sales of $68.6 million, and the decrease in natural gas prices resulted in a decrease in natural gas sales of $21.4 million.

Oil, natural gas and NGL production

Production increased 5,943 MBoe, or 78% for the three-month period ended June 30, 2026, as compared to the three-month period ended June 30, 2025. The increase was primarily a result of the IKAV and Sabinal Acquisitions, which added 6,199 Mboe of production for the three-month period ending June 30, 2026.

Oil and natural gas derivatives

For the three-month period ended June 30, 2026, we had realized losses on derivative instruments of $18.2 million and unrealized gains of $41.7 million for total gains of $23.5 million. For the three-month period ended June 30, 2025, we had realized gains on derivative instruments of $7.0 million and unrealized gains of $48.6 million for total gains of $55.6 million. The increase in realized losses is primarily due to the significant increase in oil prices during the three-month period ending June 30, 2026.

Midstream revenue

Midstream revenue increased $3.1 million, or 50% for the three-month period ended June 30, 2026, as compared to the three-month period ended June 30, 2025, due to the acquisition of additional midstream facilities in the IKAV Acquisition in September 2025.

Product sales

Product sales decreased $1.0 million, or 14% for the three-month period ended June 30, 2026, as compared to the three-month period ended June 30, 2025. This decrease was primarily a result of decreases in the average selling price of natural gas. These decreases corresponded with the decrease in our cost of product sales noted below.

Operating Expenses

The following table summarizes our expenses for the periods indicated and includes a presentation of certain expenses on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:

($ in thousands)

Gathering and processing expense

Gathering and processing expense increased $16.2 million, or 51%, and decreased $0.64 per Boe, or 15%, for the three-month period ended June 30, 2026, as compared to the three-month period ended June 30, 2025, primarily as a result of the 130% increase in natural gas production and the 19% increase in NGL production, driven by the IKAV Acquisition. Gathering and processing expense per Boe decreased primarily as a result of the Sabinal Acquisition, where oil heavy production includes no gathering and processing expense, as well as the lower gathering and processing cost profile of the IKAV properties.

Lease operating expense

Lease operating expense increased $48.2 million, or 97% for the three-month period ended June 30, 2026, as compared to the three-month period ended June 30, 2025, primarily due to the IKAV and Sabinal Acquisitions. Lease operating expenses per Boe increased by $0.69 primarily as a result of the oil-heavy production from the Sabinal Acquisition that added to our overall cost profile.

Production taxes

Production taxes increased $8.0 million, or 77% for the three-month period ended June 30, 2026, as compared to the three-month period ended June 30, 2025. This increase was in line with the increase in oil, natural gas and NGL sales.

Midstream operating expense

Midstream operating expense increased $1.8 million, or 55% for the three-month period ended June 30, 2026, as compared to the three-month period ended June 30, 2025, due to the acquisition of additional midstream facilities in the IKAV Acquisition in September 2025.

Cost of product sales

Cost of product sales decreased $0.9 million, or 14% for the three-month period ended June 30, 2026, as compared to the three-month period ended June 30, 2025. This decrease was primarily a result of the decrease in the average selling price of natural gas. These decreases were consistent with the decrease in product sales noted above.

Depreciation, depletion, amortization and accretion expense - oil and natural gas

Depreciation, depletion, amortization and accretion expense for oil and natural gas properties increased by $29.5 million, or 46% for the three-month period ended June 30, 2026, as compared to the three-month period ended June 30, 2025. The increase is primarily the result of the IKAV and Sabinal Acquisitions which added $1.3 billion to the balance of oil and gas properties subject to depletion.

General and administrative costs

General and administrative costs increased $1.9 million, or 21% for the three-month period ended June 30, 2026, as compared to the three-month period ended June 30, 2025. The increase is primarily due to increases in compensation and benefits of $1.6 million, consulting and professional fees of $1.6 million and equity compensation of $1.3 million. These increases were partially offset by additional cost recovery per the terms of joint operating agreements from acquired wells subsequent to June 30, 2025.

Six Months Ended June 30, 2026 Compared to the Six Months Ended June 30, 2025

Revenue

The following table provides the components of our revenue, net of transportation and marketing costs, for the periods indicated, as well as each period’s respective average realized prices and net production volumes. Some totals and changes throughout the below section may not sum or recalculate due to rounding.

($ in thousands)

(1) Not Meaningful

Revenue and Other Operating Income

Oil, natural gas and NGL sales

Revenues from oil, natural gas and NGL sales increased $260.3 million, or 55% for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. This increase was primarily related to the 86% production increase, which resulted in increased oil, natural gas and NGL sales of $240.3 million. Additionally, the increase in oil and NGL prices resulted in an increase in sales of $59.4 million, and the decrease in natural gas prices resulted in a decrease in natural gas sales of $39.4 million.

Oil, natural gas and NGL production

Production increased 12,838 MBoe, or 86% for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. The increase was primarily a result of the IKAV and Sabinal Acquisitions, which added 12,867 Mboe of production for the six-month period ending June 30, 2026.

Oil and natural gas derivatives

For the six-month period ended June 30, 2026, we had realized losses on derivative instruments of $11.3 million and unrealized losses of $62.1 million for total losses of $73.4 million. For the six-month period ended June 30, 2025, we had realized gains on derivative instruments of $8.7 million and unrealized gains of $6.2 million for total gains of $14.9 million. The increase in both realized and unrealized losses is primarily from an increase in oil prices throughout the six-month period ending June 30, 2026

Midstream revenue

Midstream revenue increased $6.6 million, or 53% for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025, due to the acquisition of additional midstream facilities in the IKAV Acquisition in September 2025.

Product sales

Product sales decreased $2.0 million, or 12% for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. This decrease was primarily a result of the decrease in the average selling price of natural gas. These decreases corresponded with the decrease in our cost of product sales noted below.

Operating Expenses

The following table summarizes our expenses for the periods indicated and includes a presentation of certain expenses on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:

($ in thousands)

Gathering and processing expense

Gathering and processing expense increased $47.3 million, or 79%, and decreased $0.16 per Boe, or 4%, for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025, primarily as a result of the 144% increase in natural gas production and the 19% increase in NGL production, driven by the IKAV Acquisition. Additionally, due to changes in certain purchaser contracts in the second quarter of 2025, certain post-production costs that were previously presented as a reduction to gas revenue are now presented as gathering and processing expense. Gathering and processing expense per Boe decreased primarily as a result of the Sabinal Acquisition, where oil heavy production includes no gathering and processing expense, as well as the lower gathering and processing cost profile of the IKAV properties.

Lease operating expense

Lease operating expense increased $100.3 million, or 102% for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025, primarily primarily due to the IKAV and Sabinal Acquisitions. Lease operating expenses per Boe increased by $0.56 primarily as a result of the oil-heavy production from the Sabinal Acquisition that added to our overall cost profile.

Production taxes

Production taxes increased $11.8 million, or 51% for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. This increase was in line with the increase in oil, natural gas and NGL sales.

Midstream operating expense

Midstream operating expense increased $3.9 million, or 64% for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025, primarily due to the acquisition of additional midstream facilities in the IKAV Acquisition in September 2025.

Cost of product sales

Cost of product sales decreased $2.1 million, or 15% for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. This decrease was primarily a result of the decrease in the average selling price of natural gas. These decreases were consistent with the decrease in product sales noted above.

Depreciation, depletion, amortization and accretion expense - oil and natural gas

Depreciation, depletion, amortization and accretion expense for oil and natural gas properties increased by $62.4 million, or 50% for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. The increase is primarily the result of the IKAV and Sabinal Acquisitions which added $1.3 billion to the balance of oil and gas properties subject to depletion.

General and administrative costs

General and administrative costs decreased $0.2 million, or 1% for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. The decrease in general and administrative costs was primarily a result of additional cost recovery per the terms of joint operating agreements from acquired wells subsequent to June 30, 2025. These reductions to general and administrative costs were offset by increases in compensation and benefits of $3.8 million, consulting and professional fees of $3.3 million and equity compensation of $2.7 million for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025.

Liquidity and Capital Resources

Our primary sources of liquidity and capital are cash flows generated by operating activities, borrowings under the New Credit Agreement, and proceeds from the issuance of equity and debt. At June 30, 2026, outstanding borrowings under the New Credit Agreement were $1.18 billion with $5.0 million in letters of credit outstanding, and the remaining availability under the New Credit Agreement was $270.0 million at June 30, 2026.

We may need to utilize the public equity or debt markets and bank financings to fund future acquisitions or capital expenditures, but the price at which our common units will trade could be diminished as a result of the limited voting rights of unitholders. We expect to be able to issue additional equity and debt securities from time to time as market conditions allow to facilitate future acquisitions. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations or to refinance our indebtedness will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil and natural gas, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory, weather and other factors.

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner, which we refer to as “available cash.” Our quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of our business, including those caused by fluctuations in commodity prices. Any such variations may be significant, and as a result, we may pay limited or even no cash distributions to our unitholders.

Historically, our business plan has focused on acquiring and then exploiting the development and production of our assets. We spent approximately $171.8 million during the six-month period ended June 30, 2026 on development costs and our budget for 2026 is between $310.0 million and $340.0 million. For purposes of calculating our cash available for distribution, we define development costs as all of our capital expenditures, other than acquisitions. Our development efforts and capital for 2026 is anticipated to focus on a mix of drilling Oswego, Woodford, and Mississippian wells.

During the six-month period ended June 30, 2026, we spent approximately $130.4 million on drilling and completion activities and related equipment, $31.8 million on remedial workovers and other capital projects, $9.6 million on midstream and other property and equipment capital projects. Our operated drilling program spud 8.7 net wells while bringing online 7.7 net wells for during the six-month period ended June 30, 2026.

Our 2026 capital expenditures program is largely discretionary and within our control. We could choose to defer a portion of these planned 2026 capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, including acid to be used for our acid stimulation completion, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows and reduce our cash available for distribution to unitholders.

Cash Flows

The following table summarizes our cash flows for the periods indicated:

(in thousands)

Net cash provided by operating activities

Net cash provided by operating activities increased $51.3 million for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. The increase in net cash provided by operating activities is primarily a result of increases in production across all products and increases in the average selling price of oil. These increases were offset by a decrease in the average selling price of natural gas and a decrease in cash receipts (payments) on settlement of derivative contracts of $13.7 million.

Net cash used in investing activities

Net cash used in investing activities decreased $56.4 million for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. The decrease in net cash used in investing activities is primarily a result of decreases in cash used to acquire assets of $98.6 million in the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. This was slightly offset by increases in capital expenditures on our oil and gas properties and on our other property and equipment of $35.7 million and $5.8 million, respectively, due to increased drilling and completion activities in the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025.

Net cash used in financing activities

Net cash used in financing activities increased $17.1 million for the six-month period ended June 30, 2026, as compared to the six-month period ended June 30, 2025. The increase was primarily driven by a $219.4 million decrease in proceeds from common unit issuances, a $540.0 million decrease in net borrowings under our credit facilities (proceeds net of repayments), and a $43.3 million increase in distributions to unitholders. These were largely offset by a $763.1 million decrease in term note repayments, a $7.7 million decrease in debt extinguishment costs, and a $14.7 million decrease in debt issuance costs, as we incurred no such costs in the current period.

Debt Agreements

New Credit Agreement

On February 27, 2025, the Company entered into the New Credit Agreement, among the Company, the lenders and issuing banks party thereto from time to time and Truist Bank, as the administrative agent and collateral agent. The New Credit Agreement is secured by substantially all of our assets.

The New Credit Agreement has (i) an initial borrowing base and elected commitment amount of $750.0 million, with a maximum commitment amount of $2.0 billion subject to borrowing base availability, (ii) a maturity date of February 27, 2029 and (iii) an interest rate equal to, at the Company’s election, (a) term SOFR (subject to a 0.10% per annum adjustment) plus a margin ranging from 3.00-4.00% per annum or (b) a base rate plus a margin ranging from 2.00-3.00% per annum, with the margin dependent upon borrowing base utilization at the time of determination. The Company is also required to pay a commitment fee of 0.50% per annum on the daily unused portion of the current aggregate commitments under the New Credit Agreement.

The New Credit Agreement’s borrowing base is redetermined semi-annually, in April and October. The New Credit Agreement requires the Company to maintain as of the last day of each fiscal quarter (i) a consolidated total net leverage ratio of less than or equal to 3.00 to 1.00, and (ii) a current ratio of no less than 1.00 to 1.00.

The Company used borrowings from the New Credit Agreement, together with cash on hand and proceeds from the February 2025 Offering, to repay the Term Loan Credit Agreement and the Revolving Credit Agreement in full.

On September 12, 2025, the Company entered into the First Amendment, together with certain of its subsidiaries party thereto, the lenders and issuing banks party thereto and Truist Bank, as administrative and collateral agent (the “First Amendment”). The First Amendment, among other things, (a) removes the 0.10% per annum credit spread adjustment otherwise applicable to the determination of Term SOFR (as defined in the New Credit Agreement), (b) excludes up to $750.0 million in principal amount of Borrowing Base Reduction Debt (as defined in the New Credit Agreement) issued prior to December 31, 2025 from the provisions otherwise requiring a borrowing base reduction as a result of the issuance of such indebtedness and (c) provides for (i) a $700.0 million aggregate increase in the borrowing base under the New Credit Agreement and (ii) the establishment of aggregate term loan commitments (prior to giving effect to any prior funding of term loans) in an amount of $450.0 million and the funding of any unfunded term loan commitments thereunder and increase the Aggregate Elected Revolving Commitment Amount (as defined in the New Credit Agreement) to $1.0 billion.

We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in consolidated debt or losses.

Contractual Obligations and Commitments

As part of the IKAV Acquisition, we are now party to a firm sales contract to deliver and sell a certain amount of natural gas at a fixed price of $1.72 per MMbtu through 2030. We expect to fulfill the delivery commitments primarily with production from proved developed reserves. Our production has been sufficient to satisfy the delivery commitments during the periods presented, and we expect our future production will continue to be the primary means of fulfilling the future commitments. However, if the Company’s production is not sufficient to satisfy its delivery commitments, it may be required to compensate the counterparty for the shortfall based on the difference between the market price and the fixed contract price. For further information on firm sales commitments, see Note 10 of our consolidated financial statements.

Operating lease obligations

Our operating lease obligations include long-term lease payments for office space, vehicles, equipment related to exploration, development and production activities. We paid approximately $4.9 million and $2.6 million in operating lease payments for the three and six month periods ended June 30, 2026, respectively, and expect to pay approximately $23.7 million in operating lease payments through 2031. For further information on our operating lease obligations, see Note 11 of our consolidated financial statements.

Non-GAAP Financial Measures

Adjusted EBITDA

We include in this Quarterly Report the supplemental non-GAAP financial performance measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income, our most directly comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income before (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized (gain) loss on derivative instruments, (4) loss on debt extinguishment, (5) equity-based compensation expense and (6) gain (loss) on sale of assets, net.

Adjusted EBITDA is used as a supplemental financial performance measure by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to more effectively evaluate our operating performance and our results of operation from period to period and against our peers without regard to financing methods, capital structure or historical cost basis. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA is not a measurement of our financial performance under GAAP and should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as indicators of our operating performance. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual items. Our computations of Adjusted EBITDA may not be identical to other similarly titled measures of other companies.

Cash Available for Distribution

Cash available for distribution is not a measure of net income or net cash flow provided by or used in operating activities as determined by GAAP. Cash available for distribution is a supplemental non-GAAP financial performance measure used by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as net income adjusted for (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized (gain) loss on derivative instruments, (4) loss on debt extinguishment, (5) equity-based compensation expense, (6) gain (loss) on sale of assets, net, (7) cash interest expense, net, (8) development costs and (9) change in accrued realized derivative settlements. Development costs include all of our capital expenditures, other than acquisitions. Cash available for distribution will not reflect changes in working capital balances. Cash available for distribution is not a measurement of our financial performance or liquidity under GAAP and should not be considered as an alternative to, or more meaningful than, net income or net cash provided by or used in operating activities as determined in accordance with GAAP or as indicators of our financial performance and liquidity. The GAAP measure most directly comparable to cash available for distribution is net income. Cash available for distribution should not be considered as an alternative to, or more meaningful than, net income.

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to GAAP Financial Measures

($ in thousands)

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates” in our Annual Report for the year ended December 31, 2025. No modifications have been made during the six months ended June 30, 2026.

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses.

Commodity Price Risk

Oil and gas revenue

Our revenue and cash flow from operations are subject to many variables, the most significant of which is the volatility of commodity prices. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by global economic factors, pipeline capacity constraints, inventory levels, basis differentials, weather conditions and other factors. Commodity prices have long been volatile and unpredictable, and we expect this volatility to continue in the future.

There can be no assurance that commodity prices will not be subject to continued wide fluctuations in the future. A substantial or extended decline in such prices could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil and gas reserves that may be economically produced, which could result in impairments of our oil and natural gas properties.

Commodity derivative activities

To reduce the impact of fluctuations of commodity prices on our total revenue and other operating income, we have historically used, and we expect to continue to use, commodity derivative instruments, primarily swaps, to hedge price risk associated with a portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate the potential effects of the variability in cash flow from operations due to fluctuations in commodity prices and provide increased certainty of cash flows for funding our drilling program and debt service requirements. These instruments provide only partial price protection against declines in prices and may partially limit our potential gains from future increases in prices. We do not enter derivative contracts for speculative trading purposes. The New Credit Agreement contains various covenants and restrictive provisions which, among other things, limit our ability to enter into commodity price hedges exceeding a certain percentage of production.

Our hedging activities are intended to support oil and natural gas prices at targeted levels and manage our exposure to natural gas price volatility. Under swap contracts, the counterparty is required to make a payment to us for the difference between the swap price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the swap price. We are required to make a payment to the counterparty for the difference between the swap price and the settlement price if the swap price is below the settlement price. See Note 7 of our consolidated financial statements for further information on our open derivative positions and valuation as of June 30, 2026.

Counterparty and Customer Credit Risk

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of a contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. As of June 30, 2026, we had derivative instruments in place with seven different counterparties. We believe our counterparties currently represent acceptable credit risks. We are not required to provide credit support or collateral to our counterparties under current contracts, nor are they required to provide credit support or collateral to us.

Substantially all of our revenue and receivables result from oil and gas sales to third parties operating in the oil and gas industry. Our receivables also include amounts owed by joint interest owners in the properties we operate. Both our purchasers and joint interest partners have recently experienced the impact of significant commodity price volatility as discussed above under “— Commodity Price Risk — Oil and Gas Revenue.” This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in commodity prices and economic and other conditions. In the case of joint interest owners, we often have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings.

Interest Rate Risk

Variable rate debt

At June 30, 2026, we had $1.18 billion of debt outstanding under the New Credit Agreement. Borrowings outstanding under the New Credit Agreement bore an interest rate of 7.8% as of June 30, 2026. Assuming no change in the amount outstanding, the impact on interest expense of a 1% (or 100 basis points) increase or decrease in the assumed weighted average interest rate on our variable interest debt would be approximately $11.8 million per year based on our borrowings outstanding at June 30, 2026.

Interest rate derivative activities

As of June 30, 2026, we did not have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness, but we may enter into such derivative arrangements in the future. To the extent we enter into any such interest rate derivative arrangement, we would be subject to risk for financial loss.

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2026. Based on such evaluation, such officers have concluded that, as of June 30, 2026, the Company’s disclosure controls and procedures are designed and effective to ensure that information required to be included in the Company’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information required to be disclosed in the Company’s reports filed or submitted under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating the Company’s disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company’s controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the three-month period ended June 30, 2026 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

There have been no material changes to the Company’s “Risk Factors” previously disclosed in Part I, Item 1A of our Annual Report for the year ended December 31, 2025. For a detailed discussion of the risks that affect our business, please refer to Part I, Item 1A “Risk Factors” in our Annual Report for the year ended December 31, 2025.