Mach Natural Resources LP: Form 10-Q for the period ended Sep 30, 2023

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 Report. The following discussion contains forward looking statements that reflect our future plans, estimates, beliefs and expectations. We caution that assumptions, expectations, projections, intentions or beliefs about future events may vary materially from actual results. Some of the key factors that could cause actual results to vary from expectations include those factors discussed below and elsewhere in this Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See the section entitled “Cautionary Statement Regard Forward-Looking Statements” elsewhere in this Report and “Risk Factors” in the Company’s Final Prospectus for further information on items that could impact our future operating performance or financial condition. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Unless otherwise indicated, the historical financial information as of September 30, 2023 and for the three and nine months ended September 30, 2023 presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” speaks only with respect to BCE-Mach III and does not give pro forma effect to our corporate reorganization described in “—Factors Affecting the Comparability of Our Future Result of Operations to Our Historical Results of Operations—Corporate Reorganization.”

Investors are cautioned that the forward-looking statements contained in this section and other parts of this Report involve both risk and uncertainty. Several important factors could cause actual results to differ materially from those anticipated by these statements. Many of these statements are macroeconomic in nature and are, therefore, beyond the control of management. See “Cautionary Statement Regarding Forward-Looking Statements” above and the Registration Statement.

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. Our assets are located throughout Western Oklahoma, Southern Kansas and the panhandle of Texas.

Within our operating areas, our assets are prospective for multiple formations, most notably the Oswego and Meramec/Osage formations. Our experience in the Anadarko Basin and 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. Oil prices have been affected by increased demand, domestic supply reductions, OPEC+ control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. For example, during the period from December 31, 2020 through September 30, 2023, prices for crude oil and natural gas reached a high of $123.64 per Bbl and $23.86 per MMBtu, respectively, and a low of $47.47 per Bbl and $1.74 per MMBtu, respectively. Starting in 2022, NYMEX oil and natural gas futures prices strengthened following the reduction of pandemic-related restrictions and increased OPEC+ cooperation. During the first quarter of 2023, the price of crude oil decreased as the global oil market saw higher inventory levels; however, prices remained above the 10-year average from 2010 through 2019. The increase in inventory levels was followed by an early June announcement from OPEC+ oil producers to further reduce oil output. The Energy Information Administration (“EIA”) forecasts global oil inventories to fall slightly in each of the next five quarters and projects these draws will put upward pressure on crude oil prices, notably in late-2023 and early-2024. Also during the first quarter of 2023, natural gas prices remained above the 10-year range, despite declining significantly in the quarter as milder weather eased demand for natural gas heating, allowing storage levels to increase above historical averages in the United States and Europe. The EIA projects that the U.S. benchmark Henry Hub natural gas spot price to rise in the summer months due to rising natural gas use in the electric power sector and flattening production growth, which together contribute to storage injections that are less than the five-year average from 2018 through 2022 in the coming months.

Further, although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, which has continued into 2023, due to a substantial increase in the money supply, a stimulative fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. Inflation rose from 7.5% in January 2022 to a peak of 9.1% in June 2022 and then decreased to 6.5% in December 2022. In September 2023, inflation was 3.7%. We cannot predict the future inflation rate but to the extent inflation remains elevated, we may experience 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:

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

Non-GAAP Financial Measures

Adjusted EBITDA

We include in this 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 measures calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income before (1) interest expense and interest income, (2) depreciation, depletion, amortization and accretion, (3) unrealized (gain) loss on derivative settlements, (4) equity-based compensation expense, and (5) (gain) loss on sale of assets.

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 less (1) interest expense and interest income, (2) depreciation, depletion, amortization and accretion, (3) unrealized (gain) loss on derivative settlements, (4) equity-based compensation expense, (5) (gain) loss on sale of assets, (6) settlement of asset retirement obligations, (7) cash interest expense and cash interest income, (8) development costs, (9) settlement of contingent consideration and (10) 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 measures most directly comparable to cash available for distribution are net income and net cash provided by operating activities. Cash available for distribution should not be considered as an alternative to, or more meaningful than, net income or net cash provided by operating activities.

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

($ in thousands)

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

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Initial Public Offering

On October 27, 2023, MNR completed its initial public offering (the “Offering”) for in which it issued and sold 10,000,000 common units at a public offering price of $19.00 per unit. MNR received net proceeds of $170.0 million after deducting underwriting discounts and commissions and offering expenses borne by us. The material terms of the Offering are described in the Registration Statement. MNR utilized the proceeds from its initial public offering to pay down the Existing Credit Facilities of $103.7 million, as well as repurchase common units from existing holders for approximately $66.3 million. After giving effect to the Offering and the transactions related thereto, MNR had 95,000,000 common units issued and outstanding.

Upon completion of the Offering, MNR has incurred and expects to continue incurring additional significant and recurring expenses as a publicly traded partnership, including costs associated with the employment of additional personnel, compliance under the Securities Act and Exchange Act, annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. The direct, incremental general and administrative expenses are not included in the BCE-Mach III historical financial statements.

Corporate Reorganization

On October 25, 2023, MNR underwent a corporate reorganization (“Corporate Reorganization”) whereby (a) the Existing Owners who directly held membership interests in the Mach Companies contributed 100% of their membership interests in the Mach Companies for a pro rata allocation of 100% of the limited partner interests in MNR to effectuate a merger of such entities into MNR with BCE-Mach III determined as the accounting acquirer, (b) MNR contributed 100% of its membership interests in the Mach Companies to Intermediate in exchange for 100% of the membership interests in Intermediate, and (c) Intermediate contributed 100% of its membership interests in the Mach Companies to Holdco in exchange for 100% of the membership interests in Holdco.

The unaudited financial statements of BCE-Mach III as of September 30, 2023 and December 31, 2022, and for the three and nine months ended September 30, 2023 and 2022, do not include any information from BCE-Mach or BCE-Mach II. Accordingly, the financial information for the nine months ended September 30, 2023 and 2022, may not yield an accurate indication of what our actual results would have been if the Offering and the Corporate Reorganization had been completed at the beginning of the period presented or of what our future results of operations are likely to be in the future.

Acquisitions

We completed five acquisitions between January 1, 2022 and September 30, 2023. Four of these acquisitions occurred in 2022, for a total combined purchase price of approximately $155 million, and one occurred in 2023 with a purchase price of $20 million. In all five acquisitions, substantially all of the purchase price was allocated to proved oil and natural gas properties. 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.

On January 1, 2023, we assumed operations of a significant amount of properties where we previously were a non-operating partner in the properties and provided midstream services. As a result of these properties becoming operated properties as opposed to non-operated properties, offsetting accounting changes occurred resulting in reduced midstream operating expense, reduced midstream revenue, increased LOE, and increased price realizations. In August 2023, we acquired the interest of this non-operating partner for approximately $20 million.

Results of Operations

Three Months Ended September 30, 2023 Compared to the Three Months Ended September 30, 2022

Revenue

The following table provides the components of the Company’s 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) Average sales prices reflected above exclude gathering and processing expense and the separate benefit of third party midstream revenues.

Revenue and other operating income

Oil, natural gas and NGL sales

Revenues from oil, natural gas and NGL sales decreased $91.7 million, or 35% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022. This decrease was primarily a result of a 12% decrease in the average selling price on oil resulting in a decrease in oil sales revenue of $14.5 million, a 67% decrease in the average selling price on natural gas resulting in a decrease in natural gas sales revenue of $70.5 million, and a 40% decrease on the average selling price on NGLs resulting in a decrease in NGL sales revenue of $12.0 million. An increase in production of 150 MBoe for the three-month period ended September 30, 2023, compared to the three-month period ended September 30, 2022, resulted in an increase in oil, natural gas and NGL revenues of $5.2 million.

Oil and Natural Gas Derivatives

For the three-month period ended September 30, 2023, the Company had realized losses on derivative instruments of $3.2 million and unrealized losses of $1.7 million for total losses of $4.9 million. For the three-month period ended September 30, 2022, the Company had realized losses on derivative instruments of $26.6 million and unrealized gains of $24.9 million for total losses of $1.7 million. The decrease in realized losses is primarily from the overall decrease in oil and gas prices in the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022.

Production

Production increased 150 MBoe, or 3% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022. The increase was primarily attributable to an increase in new production from wells that were brought on-line as a result of increased drilling activity subsequent to September 30, 2022, partially offset with natural production declines on our existing wells.

Product sales

Product sales decreased $20.1 million, or 74% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022. This decrease was primarily a result of decreases in non-operated production resulting in lower overall product sales, compounded by the decrease in the average selling price on natural gas and NGLs. These decreases corresponded with the decrease in our cost of product sales noted below.

Midstream revenue

Midstream revenue decreased $5.4 million, or 45% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022, primarily due to lower non-operated volumes running through our midstream facilities. Of the total decrease, $2.9 million relates to decreases in fee revenue related to gathering and processing, and $2.5 million is due to decreased saltwater gathering and disposal revenue.

Operating expenses

The following table summarizes the Company’s 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)

27

Gathering and processing expense

Gathering and processing expense decreased by $7.2 million, or 47% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022, primarily due to decreased natural gas prices leading to lower fuel costs. Gathering and processing expense per Boe produced decreased by $1.70 due to lower fuel expense that fluctuated with the decrease in commodity gas prices.

Lease operating expense

Lease operating expense increased $0.4 million, or 2% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022. Lease operating expenses per Boe decreased $0.12 primarily due to the increase in production in the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022.

Midstream operating expense

Midstream operating expense decreased $1.3 million, or 32% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022, primarily due to a decrease in gathering operating expense of $0.4 million and a decrease in water disposal costs of $0.6 million, both of which decreased as a result of us taking over as operator on a significant number of wells beginning January 1, 2023.

Cost of product sales

Cost of product sales decreased $19.3 million, or 76% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022. This decrease was primarily a result of decreases in non-operated production resulting in lower overall cost of product sales, compounded by the decrease in the average selling price on natural gas and NGLs. These decreases were offset with the decrease in product sales noted above.

Production taxes

Production taxes decreased $6.8 million, or 47% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022. This decrease was primarily a result of a decrease in the average selling price on all products, partially offset by an increase in production. Production taxes as a percentage of revenue decreased from 5.6% for the three-month period ended September 30, 2022, to 4.6% for the three-month period ended September 30, 2023. The effective tax rate can have minor fluctuations due to the overall product mix and related tax deductions available for each product.

Depreciation, depletion, amortization and accretion expense

Depreciation, depletion, amortization and accretion expense for oil and natural gas properties increased by $4.8 million, or 18% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022. The increase is primarily attributable to additional drilling activities and acquisitions that added to the depletable base and increased overall production. Depreciation and amortization expense for other assets increased $0.5 million, or 44% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022, primarily due to additional assets acquired during the year.

General and administrative costs

General and administrative costs decreased $0.4 million, or 8% for the three-month period ended September 30, 2023, as compared to the three-month period ended September 30, 2022. The decrease in general and administrative costs was primarily due to a $1.2 million reduction in equity compensation expense recorded in the three-month period ended September 30, 2023, in comparison to the three-month period ended September 30, 2022, partially offset by an increase in management fees of $0.6 million in the three-month period ended September 30, 2023, in comparison to the three-month period ended September 30, 2022.

Nine Months Ended September 30, 2023 Compared to the Nine Months Ended September 30, 2022

Revenue

The following table provides the components of the Company’s 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) Average sales prices reflected above exclude gathering and processing expense and the separate benefit of third party midstream revenues.

Revenue and other operating income

Oil, natural gas and NGL sales

Revenues from oil, natural gas and NGL sales decreased $187.6 million, or 28% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022. This decrease was primarily a result of a 21% decrease in the average selling price on oil resulting in a decrease in oil sales revenue of $73.1 million, a 63% decrease in the average selling price on natural gas resulting in a decrease in natural gas sales revenue of $147.6 million, and a 42% decrease on the average selling price on NGLs resulting in a decrease in NGL sales revenue of $37.9 million. An increase in production of 1,919 MBoe for the nine-month period ended September 30, 2023, compared to the nine-month period ended September 30, 2022, resulted in an increase in oil, natural gas and NGL revenues of $71.0 million.

Oil and Natural Gas Derivatives

For the nine-month period ended September 30, 2023, the Company had realized gains on derivative instruments of $4.3 million and unrealized gains of $6.5 million for total gains of $10.8 million. For the nine-month period ended September 30, 2022, the Company had realized losses on derivative instruments of $82.7 million and unrealized gains of $8.1 million for total losses of $74.6 million. The decrease in realized losses is primarily from the overall decrease in oil and gas prices in the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022.

Production

Production increased 1,919 MBoe, or 17% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022. The increase was primarily attributable to an increase in new production from wells that were brought on-line as a result of increased drilling activity subsequent to September 30, 2022, partially offset with natural production declines on our existing wells. Additionally, we closed on five acquisitions throughout the nine-month period ended September 30, 2022. Accordingly, the nine-month period ended September 30, 2023 includes a full nine-months of production for these wells, whereas 2022 includes only partial periods of production on these acquired wells.

Product sales

Product sales decreased $50.6 million, or 68% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022. This decrease was primarily a result of decreases in non-operated production resulting in lower overall product sales, compounded by the decrease in the average selling price on natural gas and NGLs. These decreases corresponded with the decrease in our cost of product sales noted below.

Midstream revenue

Midstream revenue decreased $11.9 million, or 37% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022, primarily due to lower non-operated volumes running through our midstream facilities. Of the total decrease, $6.3 million relates to decreases in fee revenue related to gathering and processing, and $5.6 million is due to decreased saltwater gathering and disposal revenue.

Operating expenses

The following table summarizes the Company’s 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)

30

Gathering and processing expense.

Gathering and processing expense decreased by $10.5 million, or 29% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022, primarily due to decreased natural gas prices leading to lower fuel costs. Gathering and processing expense per Boe produced decreased by $1.26 due to lower fuel expense that fluctuated with the decrease in commodity gas prices.

Lease operating expense

Lease operating expense increased $21.5 million, or 32% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022. Lease operating expense increased primarily as a result of additional wells brought on-line as a result of the drilling activity subsequent to September 30, 2022. Additionally, we closed on five acquisitions throughout the nine-month period ended September 30, 2022. Accordingly, the nine-month period ended September 30, 2023 includes a full nine-months of lease operating expense for these wells, whereas 2022 includes only partial periods of lease operating expense on these acquired wells. Lease operating expenses per Boe increased $0.75 primarily due to the increase in production in the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022.

Midstream operating expense

Midstream operating expense decreased $2.7 million, or 25% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022, primarily due to a decrease in plant operating expense of $1.2 million and a decrease in water disposal costs of $1.4 million, both of which decreased as a result of us taking over as operator on a significant number of wells beginning January 1, 2023.

Cost of product sales

Cost of product sales decreased $48.7 million, or 69% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022. This decrease was primarily a result of decreases in non-operated production resulting in lower overall cost of product sales, compounded by the decrease in the average selling price on natural gas and NGLs. These decreases were offset with the decrease in product sales noted above.

Production taxes

Production taxes decreased $14.0 million, or 38% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022. This decrease was primarily a result of a decrease in the average selling price on all products, partially offset by an increase in production. Production taxes as a percentage of revenue decreased from 5.6% for the nine-month period ended September 30, 2022, to 4.8% for the nine-month period ended September 30, 2023. The effective tax rate can have minor fluctuations due to the overall product mix and related tax deductions available for each product.

Depreciation, depletion, amortization and accretion expense.

Depreciation, depletion, amortization and accretion expense for oil and natural gas properties increased by $33.6 million, or 60% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022. The increase is primarily attributable to additional drilling activities and acquisitions that added to the depletable base and increased overall production. Depreciation and amortization expense for other assets increased $1.3 million, or 41% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022, primarily due to additional assets acquired during the year.

General and administrative costs

General and administrative costs decreased $4.2 million, or 22% for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022. The decrease in general and administrative costs was primarily due to a $3.7 million reduction in equity compensation expense recorded in the nine-month period ended September 30, 2023, in comparison to the nine-month period ended September 30, 2022, and an increase in operator overhead billed out as a result of new producing wells from acquisitions and newly drilled wells. These decreases were partially offset by an increase in management fees of $1.7 million in the nine-month period ended September 30, 2023, in comparison to the nine-month period ended September 30, 2022.

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are from cash flow generated by operating activities and borrowings under our credit facilities. Outstanding borrowings under the BCE-Mach III Credit Facility were $84.9 million at December 31, 2022 and $91.9 million at September 30, 2023. On November 10, 2023, the BCE-Mach III Credit Facility was repaid and the Existing Credit Facilities were terminated. Historically, our primary sources of liquidity have also included capital contributions by our equity holders, but we do not expect to rely on management or our partners for capital. MNR 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. MNR expects to be able to issue additional equity and debt securities from time to time as market conditions allow to facilitate future acquisitions. MNR expects to reduce any debt incurred to complete such acquisitions in order to meet the long-term goal of maintaining a low leverage profile and funding the development plan with cash flow from operating activities. MNR’s ability to finance operations, including funding capital expenditures and acquisitions, to meet its indebtedness obligations or to refinance its indebtedness will depend on MNR’s ability to generate cash in the future. MNR’s ability to generate cash is subject to a number of factors, some of which are beyond its control, including commodity prices, particularly for oil and natural gas, and its ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory, weather and other factors.

MNR’s partnership agreement requires it to distribute all cash on hand at the end of each quarter, less reserves established by the General Partner, which is referred to as “available cash.” Nevertheless, the quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of MNR’s business, including those caused by fluctuations in commodity prices. Any such variations may be significant, and as a result, MNR may pay limited or even no cash distributions to unitholders.

Our business plan has focused on acquiring and then exploiting the development and production of our assets. We spent approximately $258.9 million in the nine-month period ended September 30, 2023, on development costs and our budget for 2023 is approximately $316.2 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 2023 is focused on drilling Oswego wells given their high oil reserves and low breakeven costs.

During the nine-month period ended September 30, 2023, we spent approximately $225.8 million on drilling, completion and related equipment, spudding 58.9 net wells and turning 61.1 net wells to production, $24.1 million on remedial workovers and other capital projects, $9.0 million on midstream and other property and equipment capital projects, and $21.3 million on acquisitions.

MNR’s 2024 capital expenditures program is largely discretionary and within our control. We could choose to defer a portion of these planned 2024 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.

Based on current oil and natural gas price expectations for 2024, we believe that our cash flow from operations, together with borrowings from time to time under our New Credit Facility, will be sufficient to fund our operations through 2024. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. For example, we expect a portion of our future capital expenditures to be financed with cash flows from operations derived from wells drilled on drilling locations not classified as proved reserves in our current reserve report. The failure to achieve anticipated production and cash flow from operations from such wells could result in a reduction in future capital spending and/or our ability to pay distributions to unitholders. We cannot assure you that operations and other needed capital will be available on acceptable terms or at all.

Cash flows

The following table summarizes the Company’s cash flows for the periods indicated:

(in thousands)

Net cash provided by operating activities

Net cash provided by operating activities decreased by $16.3 million for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022. The decrease in net cash provided by operating activities is primarily attributable to the decrease in realized pricing for the nine-month period ended September 30, 2023 as compared to the nine-month period ended September 30, 2022. The decrease in realized pricing was partially offset with an increase in production from period to period. Additionally, we received $5.2 million in cash related to derivative settlements in the nine-month period ended September 30, 2023, compared to paying derivative settlements of $85.5 million in the nine-month period ended September 30, 2023, resulting in a net change of derivative settlements of $90.7 million.

Net cash used in investing activities

Net cash used in investing activities decreased $14.6 million for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022. The decrease in net cash used in investing activities is primarily attributable to a decrease in cash used for acquisitions of $107.9 million, partially offset by an increase of cash used for drilling, completion and workover activities of $90.9 million.

Net cash used in financing activities

Net cash used in financing activities decreased $41.0 million for the nine-month period ended September 30, 2023, as compared to the nine-month period ended September 30, 2022. The decrease in net cash used in financing activities is primarily attributable to a decrease in distributions to members of $78.5 million. This was partially offset with a decrease in contributions from members of $45.0 million in 2023. Additionally, there was also an increase in borrowings on the BCE-Mach III Credit Facility of $7.0 million.

Debt agreements

Previous Credit Facility

The Company entered into a credit agreement for a revolving credit facility with a syndicate of banks, including MidFirst Bank, who served as administrative agent and issuing bank. The BCE-Mach III Credit Facility provided for a maximum outstanding amount of $400.0 million, subject to commitments of $100.0 million as of September 30, 2023. The BCE-Mach III Credit Facility matured in May 2026. Outstanding obligations under the BCE-Mach III Credit Facility were secured by substantially all of our BCE-Mach III’s assets. As of September 30, 2023, there was $91.9 million outstanding under the BCE-Mach III Credit Facility.

The credit agreement governing the BCE-Mach III Credit Facility contained various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios. As of September 30, 2023, and December 31, 2022, BCE-Mach III was in compliance with all applicable covenants under the BCE-Mach III Credit Facility.

Outstanding borrowings under the BCE-Mach III Credit Facility bore interest at a per annum rate that is equal to the Term SOFR rate plus the applicable margin. BCE-Mach III was obligated to pay a quarterly commitment fee on the unused portion of the commitment, which fee was also dependent on the amount of loans and letters of credit outstanding. The effective interest rate as of September 30, 2023, and December 31, 2022, was 8.7% and 7.7%, respectively. On November

10, 2023, the proceeds from the New Credit Facility were used, in part, to repay and terminate the BCE-Mach III Credit Facility.

New Credit Facility

On November 10, 2023, Holdco entered into the New Credit Facility with a syndicate of banks, including MidFirst Bank who serves as sole book runner and lead arranger. Outstanding obligations under the New Credit Facility are secured by substantially all of Holdco’s assets. In connection with the New Credit Facility, each of the Existing Credit Facilities were terminated.

The aggregate principal amount of loans outstanding under the New Credit Facility as of November 10, 2023 was $130 million (which includes $5 million of issued letters of credit). The New Credit Facility provides for a revolving credit facility in an aggregate maximum amount of $1.0 billion, with an initial borrowing base of $600.0 million, subject to commitments of $200.0 million. The amount available to be borrowed under the New Credit Facility is subject to a borrowing base that is redetermined semiannually each May and November in an amount determined by the lenders. Certain key terms and conditions under the New Credit Facility include (but are not limited to):

• A maturity date of November 10, 2027;
• The loans shall bear interest at a per annum rate equal to the Term SOFR plus an applicable margin. The applicable margin ranges from 3% to 4% depending on the amount of loans and letters of credit outstanding;
• The unused commitments under the New Credit Facility will accrue a commitment fee, payable quarterly in arrears;
• Certain customary financial covenants, in each case that are determined as of the last day of each fiscal quarter commencing with the fiscal quarter ending December 31, 2023; and cash available for distribution; and
• Certain events of default, including, without limitation: non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy.

The New Credit Facility includes certain customary restrictions on the ability of MNR and its subsidiaries to, among other things, incur additional indebtedness, grant additional liens and make investments, acquisitions, dispositions, distributions and other payments with certain exceptions as more specifically described in the New Credit Facility.

The New Credit Facility contains customary events of default. If an event of default occurs and is continuing, then, among other things, the lenders may declare any outstanding obligations under the New Credit Facility to be immediately due and payable and exercise their rights and remedies against the collateral. The obligations under the New Credit Facility are secured by a first priority security interest in substantially all of MNR’s assets (subject to permitted liens).

Contractual obligations and commitments

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.

Operating lease obligations

We have various leasing obligations in the normal course of our operations, as discussed in Note 12 of our consolidated financial statements. There have been no other material changes to our contractual obligations from those disclosed in the Final Prospectus.

Critical Accounting Policies and Estimates

As of September 30, 2023, there have been no significant changes in our critical accounting policies from those disclosed in the Final Prospectus.

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 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 Existing Credit Facilities contain and the New Credit Facility 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 8 of our consolidated financial statements for further discussion of our derivative position and valuation as of September 30, 2023.

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 September 30, 2023, the Company had derivative instruments in place with one counterparty. 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 September 30, 2023, we had $91.9 million of debt outstanding under the BCE-Mach III Credit Facility. Borrowings outstanding under the BCE-Mach III Credit Facility bore an effective interest rate of 8.7% as of September 30, 2023. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate on our variable interest debt would be approximately $0.9 million per year based on our borrowings outstanding at September 30, 2023.

As required by Rule 13a 15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a 15(e) and 15d 15(e) under the Exchange Act) as of the end of the period covered by this Report.

Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2023.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.