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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2023
OR
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______
Commission file number 001-41849
Mach Natural Resources LP
(Exact name of registrant as specified in its charter)
Delaware93-1757616
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
14201 Wireless Way, Suite 300, Oklahoma City, Oklahoma
73134
(Address of Principal Executive Offices)(Zip Code)
(405) 252-8100
Registrant’s telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common UnitsMNRNew York Stock Exchange
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. Yes No x
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated fileroAccelerated filero
Non-accelerated filerxSmaller reporting companyo
Emerging growth companyx
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
The registrant had 95,000,000 common units outstanding as of December 7, 2023.


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DEFINITIONS
Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGL.
BCE. Investment funds managed by Bayou City Energy Management LLC and affiliates thereof.
BCE-Mach. BCE-Mach LLC, a Delaware limited liability company.
BCE-Mach Credit Facility. The reserve-based revolving credit facility that BCE-Mach entered into on September 2, 2022 with a syndicate of banks, including MidFirst Bank who served as sole book runner and lead arranger, maturing in September 2026.
BCE-Mach II. BCE-Mach II LLC, a Delaware limited liability company.
BCE-Mach II Credit Facility. The reserve-based revolving credit facility that BCE-Mach II entered into with a syndicate of banks, including East West Bank, who served as sole book runner and lead arranger.
BCE-Mach III or the Company. BCE-Mach III LLC, a Delaware limited liability company.
BCE-Mach III Credit Facility. The reserve-based revolving credit facility that the Company entered into with a syndicate of banks, including MidFirst Bank, who served as administrative agent and issuing bank.
BCE-Mach Aggregator. BCE-Mach Aggregator LLC, a Delaware limited liability company.
BCE-Stack. BCE-Stack Development LLC, a Delaware limited liability company.
Boe. One barrel of oil equivalent, converting natural gas to oil at the ratio of 6 Mcf of natural gas to one Bbl of oil.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Existing Credit Facilities. Together, the BCE-Mach Credit Facility, the BCE-Mach II Credit Facility and the BCE-Mach III Credit Facility that existed prior to the Offering.
Existing Owners. Collectively refers to BCE and the Management Members.
Holdco. Mach Natural Resources Holdco LLC, a Delaware limited liability company.
Intermediate. Mach Natural Resources Intermediate LLC, a Delaware limited liability company.
Lease operating expense. The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, ad valorem taxes, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.
LOE. Lease operating expense.
Mach Companies. Collectively refers to BCE-Mach, BCE-Mach II, and BCE-Mach III.
Mach Resources. Mach Resources LLC.
Management Members. Collectively refers to our current officers and employees who own indirect equity interests in the Mach Companies.
MBbl. One thousand barrels of crude oil, condensate or NGLs.
MBoe. One thousand Boe.
MBoe/d. One thousand Boe per day.
Mcf. One thousand cubic feet of natural gas.
MMbbl. One million barrels of oil.
MMBoe. One million Boe.
MMBtu. One million Btu.
MMcf. One million cubic feet of natural gas.
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MMcf/d. One million cubic feet of natural gas per day.
NGLs. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.
New Credit Facility. Refers to the new reserve-based revolving credit facility entered into by Holdco and MidFirst Bank on November 10, 2023.
NYMEX. The New York Mercantile Exchange.
NYSE. The New York Stock Exchange.
OPEC+. Organization of the Petroleum Exporting Countries.
Partnership agreement. The Amended and Restated Agreement of Limited Partnership of Mach Natural Resources LP.
Working interest. The right granted to the lessee of a property to explore for and to produce and own oil and natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
Workover. Operations on a producing well to restore or increase production.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Some of the information in this Quarterly Report on Form 10-Q (this “Report”) may contain “forward-looking statements.” All statements, other than statements of historical fact included in this Report regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Report, words such as “may,” “assume,” “forecast,” “could,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events at the time such statement was made. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” in our final prospectus filed with the U.S. Securities and Exchange Commission pursuant to Rule 424(b)(4), dated October 24, 2023 (the “Final Prospectus”).

Forward looking statements may include statements about:

• our business strategy;

• our estimated proved reserves;

• our ability to distribute cash available for distribution and achieve or maintain certain financial and operational metrics;

• our drilling prospects, inventories, projects and programs;

• general economic conditions, including the effects of a global health crises such as the COVID-19 pandemic;

• actions taken by OPEC + as it pertains to the global supply and demand of, and prices for, oil, natural gas and NGLs;

• our ability to replace the reserves we produce through drilling and property acquisitions;

• our financial strategy, leverage, liquidity and capital required for our development program;

• our pending legal or environmental matters;

• our realized oil and natural gas prices;

• the timing and amount of our future production of natural gas;

• our ability to reduce or offset our greenhouse gas (“GHG”) emissions, including our ability to achieve carbon neutrality;

• our hedging strategy and results;

• our competition and government regulations;

• our ability to obtain permits and governmental approvals;

• our marketing of natural gas;

• our leasehold or business acquisitions;

• our costs of developing our properties;

• credit markets;

• our decline rates of our oil and gas properties;

• uncertainty regarding our future operating results; and
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• our plans, objectives, expectations and intentions contained in this Report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil, natural gas and NGL. We disclose important factors that could cause our actual results to differ materially from our expectations as described under “Risk Factors” in the Final Prospectus. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statement include:

• commodity price volatility;

• the impact of epidemics, outbreaks or other public health events, and the related effects on financial markets, worldwide economic activity and our operations;

• the impact of COVID-19, and governmental measures related thereto, on global demand for oil and natural gas and on the operations of our business;

• uncertainties about our estimated oil, natural gas and NGL reserves, including the impact of commodity price declines on the economic producibility of such reserves, and in projecting future rates of production;

• the concentration of our operations in the Anadarko Basin;

• difficult and adverse conditions in the domestic and global capital and credit markets;

• lack of transportation and storage capacity as a result of oversupply, government regulations or other factors;

• lack of availability of drilling and production equipment and services;

• potential financial losses or earnings reductions resulting from our commodity price risk management program or any inability to manage our commodity risks;

• failure to realize expected value creation from property acquisitions and trades;

• access to capital and the timing of development expenditures;

• environmental, weather, drilling and other operating risks;

• regulatory changes, including potential shut-ins or production curtailments mandated by the Railroad Commission of Texas;

• competition in the oil and natural gas industry;

• loss of production and leasehold rights due to mechanical failure or depletion of wells and our inability to re-establish their production;

• our ability to service our indebtedness;

• any downgrades in our credit ratings that could negatively impact our cost of and ability to access capital;

• cost inflation;

• political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the war in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;

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• evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or other with authorized access, cyber or phishing-attacks, ransomware, social engineering, physical breaches or other actions; and

• risks related to our ability to expand our business, including through the recruitment and retention of qualified personnel.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, our reserve and PV-10 estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties materialize, or should underlying assumptions prove to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Report.


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PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
BCE-MACH III LLC
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands)
September 30,
2023
December 31,
2022
ASSETS
Current assets
Cash and cash equivalents$58,737 $29,417 
Accounts receivable – joint interest and other21,957 21,490 
Accounts receivable – oil, gas, and NGL sales68,160 108,277 
Inventories17,647 24,700 
Other current assets3,450 2,349 
Total current assets169,951 186,233 
Oil and natural gas properties, using the full cost method:
Proved oil and natural gas properties1,018,171 749,934 
Less: accumulated depreciation, depletion and amortization(225,604)(139,514)
Oil and natural gas properties, net792,567 610,420 
Other property, plant and equipment91,146 82,125 
Less: accumulated depreciation(13,722)(9,198)
Other property, plant and equipment, net77,424 72,927 
Other assets2,846 3,052 
Operating lease assets11,995 14,809 
Total assets$1,054,783 $887,441 
LIABILITIES AND EQUITY
Current liabilities
Accounts payable$34,106 $19,429 
Accrued liabilities36,774 60,169 
Revenue payable52,955 52,196 
Current portion of operating lease liabilities8,820 10,767 
Short-term derivative contracts3,547 10,080 
Total current liabilities136,202 152,641 
Long-term debt91,900 84,900 
Asset retirement obligations55,973 52,359 
Long-term portion of operating lease liabilities3,296 4,042 
Other long-term liabilities603 269 
Total long-term liabilities151,772 141,570 
Commitments and contingencies (Note 11)
Members equity
766,809 593,230 
Total liabilities and members equity
$1,054,783 $887,441 
The accompanying notes are an integral part of these financial statements.
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BCE-MACH III LLC
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands)
Three Months Ended
September 30,
Nine Months Ended
September 30,
2023202220232022
Revenue
Oil, natural gas, and NGL sales$166,706 $258,431 $479,319 $666,873 
Midstream revenue6,683 12,045 20,001 31,929 
Gain (loss) on oil and natural gas derivatives(4,900)(1,720)10,842 (74,577)
Product sales6,900 26,988 24,321 74,948 
Total revenues175,389 295,744 534,483 699,173 
Operating expenses
Gathering and processing7,962 15,147 25,472 35,959 
Lease operating expense28,879 28,431 89,494 68,023 
Midstream operating expense2,725 4,029 8,263 11,006 
Cost of product sales6,024 25,355 21,599 70,313 
Production taxes7,660 14,484 23,186 37,159 
Depreciation, depletion, and accretion – oil and natural gas31,277 26,446 89,372 55,820 
Depreciation and amortization – other1,758 1,217 4,551 3,225 
General and administrative5,360 5,799 15,265 19,447 
Total operating expenses91,645 120,908 277,202 300,952 
Income from operations83,744 174,836 257,281 398,221 
Other (expense) income
Interest expense(2,054)(1,317)(5,843)(3,193)
Other (expense) income, net1,795 (1,299)1,550 (178)
Total other expense(259)(2,616)(4,293)(3,371)
Net income$83,485 $172,220 $252,988 $394,850 
The accompanying notes are an integral part of these financial statements.
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BCE-MACH III LLC
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY (UNAUDITED)
(in thousands)
Total Members’
Equity
Balance at December 31, 2022$593,230 
Net income91,694 
Distributions(59,000)
Equity compensation647 
Balance at March 31, 2023$626,571 
Net income77,809 
Distributions(15,500)
Equity compensation647 
Balance at June 30, 2023$689,527 
Net income83,485 
Distributions(26,850)
Contributions20,000 
Equity compensation647 
Balance at September 30, 2023$766,809 
Balance at December 31, 2021$278,699 
Net income68,625 
Equity compensation1,882 
Balance at March 31, 2022$349,206 
Net income154,005 
Distributions(91,337)
Contributions65,000 
Equity compensation1,882 
Balance at June 30, 2022$478,756 
Net income172,220 
Distributions(88,500)
Equity compensation1,882 
Balance at September 30, 2022$564,358 
The accompanying notes are an integral part of these financial statements.
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BCE-MACH III LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)
Nine Months Ended September 30,
20232022
Cash flows from operating activities
Net income$252,988 $394,850 
Adjustments to reconcile net income to cash provided by operating activities
Depreciation, depletion and amortization93,923 59,045 
(Gain) loss on derivative instruments(10,842)74,577 
Cash receipts (payments) on settlement of derivative contracts, net5,207 (85,507)
Debt issuance costs amortization232 280 
Settlement of contingent consideration (12,925)
Equity based compensation1,941 5,646 
(Gain) loss on sale of assets(1)22 
Settlement of asset retirement obligations(445)(49)
Changes in operating assets and liabilities (decreasing) increasing cash:
Accounts receivable, inventories, other assets35,334 (63,338)
Revenue payable6,394 14,258 
Accounts payable and accrued liabilities(2,764)11,443 
Net cash provided by operating activities381,967 398,302 
Cash flows from investing activities
Capital expenditures for oil and natural gas properties(251,538)(160,557)
Capital expenditures for other property and equipment(9,083)(6,835)
Acquisition of assets(20,613)(91,282)
Acquisition of assets – related party (37,242)
Proceeds from sales of oil and natural gas properties3,305 3,429 
Proceeds from sales of other property and equipment36 18 
Net cash used in investing activities(277,893)(292,469)
Cash flows from financing activities
Distributions to members(101,350)(179,836)
Payment of other financing fees(404) 
Proceeds from long-term debt7,000  
Repayments of borrowings (900)
Contributions from members20,000 65,000 
Net cash used in financing activities(74,754)(115,736)
Net increase (decrease) in cash and cash equivalents29,320 (9,903)
Cash and cash equivalents, beginning of period29,417 59,272 
Cash and cash equivalents, end of period$58,737 $49,369 
The accompanying notes are an integral part of these financial statements.
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1.Organization and Nature of Business
BCE-Mach III LLC (“the Company,” “we,” “us,” “our,”) was formed on December 28, 2019 as a limited liability company under the laws of the State of Delaware. On December 28, 2019, the Company entered into a limited liability company agreement (the “LLC agreement”) with its initial member. The LLC agreement was amended and restated on March 25, 2021 to allow additional equity to be issued to certain employees of the Company. The Company wholly owns one subsidiary, BCE-Mach III Midstream Holdings LLC. On April 9, 2020, the Company closed on an acquisition and operations subsequently began for the Company. The Company owns and operates producing wells and undeveloped acreage primarily in Oklahoma and Texas. The Company also owns gas gathering lines, gas processing facilities, and saltwater disposal facilities.
Mach Natural Resources LP (“MNR”) is a Delaware limited partnership that was formed for the purpose of effectuating MNR’s initial public offering (the “Offering”) that closed in October 2023. The operations of MNR are governed by the provisions of the partnership agreement, executed by the general partner, Mach Natural Resources GP LLC (the “General Partner”) and the limited partners. The General Partner is managed and operated by the board of directors and executive officers of the General Partner. The members of the board of directors of the General Partner are appointed by the members of the General Partner, BCE-Mach Aggregator and Mach Resources in proportion to their respective limited partnership ownership in MNR.

Following the Offering and the transactions related thereto, MNR became a holding partnership whose sole material assets consist of membership interests in Mach Natural Resources Intermediate LLC (“Intermediate”), who wholly owns Mach Natural Resources Holdco LLC (“Holdco”). Holdco wholly owns each of MNR’s three operating subsidiaries which operate MNR’s assets, BCE-Mach LLC, BCE-Mach II LLC and BCE-Mach III LLC (collectively, the “Mach Companies”). BCE-Mach III LLC is the accounting predecessor to MNR for all periods prior to the Offering as discussed herein.

Initial Public Offering

On October 27, 2023, MNR completed the Offering of 10,000,000 common units at a price of $19.00 per unit to the public. The sale of MNR’s common units resulted in gross proceeds of $190.0 million to MNR and net proceeds of $170.0 million, after deducting underwriting fees and offering expenses. The material terms of the Offering are described in MNR’s final prospectus, filed with the U.S. Securities and Exchange Commission (“SEC”) on October 26, 2023, pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended (the “Securities Act”).

MNR used $103.7 million of the proceeds to pay down the existing credit facilities of its operating subsidiaries (the “Existing Credit Facilities”) and $66.3 million of the proceeds to purchase 3,750,000 common units from the existing common unit owners on a pro rata basis. After giving effect to the Offering and the transactions related thereto, MNR had 95,000,000 common units issued and outstanding.

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.
2.Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation
The unaudited consolidated financial statements included herein were prepared from records of the Company in accordance with generally accepted accounting principles in the United States (“US GAAP”) and include accounts of our wholly owned subsidiary. Intercompany accounts and transactions have been eliminated upon consolidation. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
the year ended December 31, 2022, as included in MNR’s final prospectus, dated October 24, 2023, filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act. Results for interim periods are not necessarily indicative of results to be expected for the full year ending December 31, 2023. In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the financial information, have been included.
Use of Estimates
The preparation of the financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the fair value determination of acquired assets and liabilities, equity-based compensation, the fair value of contingent consideration, and the fair value estimates of commodity derivatives.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the financial statements. The Company maintains cash at financial institutions which may at times exceed federally insured amounts. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk in this area.
Accounts Receivable
Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received within three months after the production date.
Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for credit losses when the Company believes collection is doubtful. The Company extends credit to joint interest owners and generally does not require collateral. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for credit losses. At September 30, 2023 and December 31, 2022, the Company’s allowance for credit losses was not material.
Derivative Instruments
The Company is required to recognize its derivative instruments on the balance sheet as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments in the statement of operations.
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Oil and Natural Gas Operations

The Company uses the full cost method of accounting for its exploration and development activities. Under this method of accounting, costs of both successful and unsuccessful exploration and development activities are capitalized as proved oil and natural gas properties. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities, which are expensed as incurred. Capitalized costs are depreciated using the unit-of production method. Under this method, depletion is computed at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by a net equivalent proved reserves at the beginning of the period. The average depletion rate per barrel equivalent unit of production was $6.52 and $4.72 for the nine months ended September 30, 2023 and 2022, respectively. The average depletion rate per barrel equivalent unit of production was $6.64 and $5.79 for the three months ended September 30, 2023 and 2022, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $86.1 million and $53.3 million for the nine months ended September 30, 2023 and 2022, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $30.2 million and $25.5 million for the three months ended September 30, 2023 and 2022, respectively.
Under the full cost method, capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the full cost “ceiling” at the end of each reporting period. The ceiling is calculated based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10%. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties. Estimated future net cash flows are calculated using the preceding 12-months’ average price based on closing prices on the first day of each month. The net book value is compared to the ceiling limitation on a quarterly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. The ceiling limitation computation is determined without regard to income taxes due to the Internal Revenue Service (“IRS”) recognition of the Company as a flow-through entity. No impairments on proved oil and natural gas properties were recorded for the three or nine months ended September 30, 2023 and 2022.
Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. As of September 30, 2023, and December 31, 2022, the Company had no properties excluded from the full cost pool. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Sales of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas, and natural gas liquids (“NGL”) reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center.
Other Property and Equipment, Net
Other property and equipment primarily consists of a gathering system, processing plant, and salt water disposal system. Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 4 to 37 years. Depreciation expense for other property and equipment was $4.6 million and $3.2 million for the nine months ended September 30, 2023 and 2022, respectively. Depreciation expense for other property and equipment was $1.8 million and $1.2 million for the three months ended September 30, 2023 and 2022, respectively.
Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
value of the asset. No impairment of other property and equipment was recorded for the three or nine months ended September 30, 2023 or 2022.
Inventories
Inventories are stated at the lower of cost or net realizable value and consist of production and midstream equipment not placed in service as of September 30, 2023 and December 31, 2022. The Company’s production equipment is primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units, as well as pipe for midstream operations.
Debt Issuance Costs
Other assets include capitalized costs related to the BCE-Mach III Credit Facility of $1.4 million, net of accumulated amortization of $1.1 million as of September 30, 2023. As of December 31, 2022, other assets include capitalized costs related to the BCE-Mach III Credit Facility of $1.0 million, net of accumulated amortization of $0.8 million. These costs are being amortized over the term of the BCE-Mach III Credit Facility and are reported as interest expense on the Company’s statement of operations.
Income Taxes
The Company operated as a limited liability company taxed as a partnership, with any associated tax liability being the responsibility of the individual members. Accordingly, no provision for income taxes was made in the consolidated financial statements.

Limited liability companies are subject to state income taxes in the state of Texas. Due to immateriality, income taxes related to the Texas margin tax have been included in general and administrative expenses on the statement of operations and no deferred tax amounts were calculated. The Company has not recognized any potential interest or penalties in its financial statements for the nine months ended September 30, 2023. The Company’s tax years 2022, 2021, and 2020 remain open for examination by state authorities.
Asset Retirement Obligations
The Company records the fair value of the future legal liability for an asset retirement obligation (“ARO”) in the period in which the liability is incurred (at the time the wells are drilled or acquired), with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the well is sold, at which time the liability is satisfied.
The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future downhole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of a field’s surface to a condition similar to that existing before oil and natural gas extraction or salt water disposal began.
In general, the amount of ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes materially, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
changes in the estimated timing of abandonment. The following is a reconciliation of ARO for the nine months ended September 30, 2023 and 2022 (in thousands):
September 30,
2023
September 30,
2022
Asset retirement obligation at beginning of period$52,359 $25,620 
Liabilities assumed in acquisitions214 18,397 
Liabilities incurred284 1,310 
Liabilities settled(479)(9)
Liabilities revised313 141 
Accretion expense3,282 2,518 
Asset retirement obligation at end of period$55,973 $47,977 
Revenue Recognition
Sales of oil, natural gas and NGL are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The Company’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and NGL fluctuates to remain competitive with other available oil, natural gas and NGL supplies.
Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and the Company expects this volatility to continue in the future. The prices the Company receives for production depend on many factors outside of our control. See Note 8 of our consolidated financial statements for a discussion of the Company’s management of price volatility.
Oil Sales
The Company’s oil sales contracts are structured where it delivers oil to the purchasers at the wellhead, where the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s statement of operations.
Natural Gas and NGL Sales
Under the Company’s natural gas and NGL sales contracts, it first delivers wet natural gas to a midstream processing entity. After processing, the residue gas is transported to the purchaser at the inlet to certain natural gas pipelines, where the purchaser takes control, title and risk of loss of the product. The NGL is delivered to the purchaser at the tailgate of the midstream processing plant, where the purchaser takes control, title and risk of loss of the product. For both natural gas sales and NGL sales, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with gathering and processing fees presented as an expense in its statement of operations.
Midstream Revenue and Product Sales
The Company’s gathering and processing revenue is generated from owned gathering and compression systems and processing plants acquired in the Company’s acquisitions. The Company charges a gathering, compression, processing rate per MMBtu transported through the gathering system and processing plant. The Company also gathers and disposes of salt water from producing wells through an owned pipeline system and disposal wells. The Company charges a fixed rate per barrel for disposal.
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Product sales are generated from the Company’s sale of natural gas, oil and NGL production purchased from third parties and subsequently gathered and processed through the Company’s owned midstream facilities. Product sales includes activity from certain third-party percent-of-proceeds contracts where the Company keeps a contractually based percentage of proceeds from the sale of natural gas and NGL production, as payment for processing natural gas from the third parties. The costs of buying natural gas, oil and NGL production from third party shippers are included as costs of product sales on the statement of operations.
Transaction Price Allocated to Remaining Performance Obligations
For the Company’s product sales that are short-term in nature with a contract term of one year or less, the Company has utilized the practical expedient that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior-Period Performance Obligations
The Company records revenue in the month production is delivered and control passes to the customer. However, settlement statements and payment may not be received for 30 to 90 days after the date production occurs, and as a result, the Company is required to estimate the amount of production that was delivered and the price that will be received for the sale of the product. The Company records variances between its estimates and actual amounts received in the month payment is received and such variances have historically not been significant.
Concentrations
The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the nine months ended September 30, 2023, three purchasers each accounted for more than 10% of the Company’s revenue: Phillips 66 Company (53.6%); NextEra Energy Marketing, LLC (13.2%); and ONEOK, INC. (10.7%). For the three months ended September 30, 2023, one purchaser accounted for more than 10% of the Company’s revenue: Phillips 66 Company (60.2%). For the nine months ended September 30, 2022, three purchasers each accounted for more than 10% of the Company’s revenue: Hinkle Oil and Gas Inc. (30.3%); Phillips 66 Company (18.5%); and NextEra Energy Marketing, LLC (16.7%). For the three months ended September 30, 2022, three purchasers each accounted for more than 10% of the Company’s revenue: Hinkle Oil and Gas Inc. (33.6%); NextEra Energy Marketing, LLC (17.2%); and Phillips 66 Company (16.1%).The Company’s receivables as of September 30, 2023, and December 31, 2022, from oil and gas sales are concentrated with the same counterparties noted above. The Company does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
As of September 30, 2023, the Company had one customer that represented approximately 45% of our total joint interest receivables. As of December 31, 2022, the Company had one customer that represented approximately 21% of our total joint interest receivables.
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Revenue Disaggregation
The following table displays the revenue disaggregated and reconciles disaggregated revenue to the revenue reported (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Revenues:
Oil$112,970 $123,405 $321,056 $342,272 
Natural gas36,564 104,678 106,263 234,269 
NGL17,017 29,783 51,561 88,811 
Gross oil, natural gas, and NGL sales166,551 257,866 478,880 665,352 
Transportation, gathering and marketing155 565 439 1,521 
Net oil, natural gas, and NGL sales$166,706 $258,431 $479,319 $666,873 
Recent Accounting Pronouncements Adopted
In June 2016, the FASB issued Accounting Standards Update 2016-13, “Financial Instrument-Credit Losses: Measurement of Credit Losses on Financial Instruments,” which amends reporting guidance on credit loses for certain financial instruments. The Company’s primary risk for credit losses related to its receivables from joint interest owners in our operated oil and natural gas wells. This guidance is effective for periods after December 15, 2022, and the Company implemented it effective January 1, 2023, with no material impacts to the financial statements.
3.Acquisitions
Subsequent to the balance sheet date, on October 25, 2023, as part of the Corporate Reorganization, the Existing Owners prior to the Offering contributed all of their equity interests in BCE-Mach LLC, BCE-Mach II LLC and BCE-Mach III LLC to MNR in exchange for 100% of the partnership interest in MNR to effectuate the acquisition. While there was a high degree of common ownership, the Mach Companies were not under common control for financial reporting purposes. BCE-Mach III LLC has been identified accounting acquirer of BCE-Mach and BCE-Mach II which have been accounted for as business combinations under the acquisition method of accounting under U.S. GAAP.

The following table presents the fair value of consideration transferred by MNR as a result of the acquisitions (amounts in thousands, except share amounts):

BCE-Mach LLCBCE-Mach II LLC
MNR common units issued for acquisition7,765,625 4,215,625 
Offering price of common units$19.00 $19.00 
Total acquisition consideration$147,547 $80,097 

The table below reflects the preliminary fair value estimates of the assets acquired and liabilities assumed as of the acquisition date. While the preliminary purchase price allocation is substantially complete as of the date of this filing, there may be further adjustments to MNR’s oil and natural gas properties. These amounts will be finalized within the
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
measurement period of the acquisition which will be no later than one year from the acquisition date. Below is a reconciliation of assets acquired and liabilities assumed (in thousands):

BCE-Mach LLCBCE-Mach II LLC
Assets acquired:
Cash and cash equivalents$25,370 $9,127 
Accounts receivable32,573 11,312 
Other current assets16,605 2,236 
Proved oil and natural gas properties, net of ARO174,915 87,991 
Other long-term assets12,381 7,655 
Total assets to be acquired261,844 118,321 
Liabilities assumed:
Accounts payable and accrued liabilities16,900 4,192 
Revenue payable28,808 15,370 
Other current liabilities1,754 450 
Long-term debt65,000 17,100 
Other long-term liabilities1,835 1,112 
Total liabilities assumed114,297 38,224 
Net assets acquired$147,547 $80,097 

Proved properties were valued using an income approach based on underlying reserves projections as of the acquisition date. The income approach is considered a Level 3 fair value estimate and includes significant assumptions of future production, commodity prices, operating and capital cost estimates, the weighted average cost of capital for industry peers, which represents the discount factor, and risk adjustment factors based on reserve category. Price assumptions were based on observable market pricing, adjusted for historical differentials, while cost estimates were based on current observable costs inflated based on historical and expected future inflation.
The following table summarizes the unaudited pro forma consolidated financial information of the Company as if the acquisitions had occurred on January 1, 2022 (in thousands):

Three Months Ended
September 30,
Nine Months Ended
September 30,
2023202220232022
Total revenues$216,761 $376,178 $670,017 $891,705 
Net income$91,704 $210,916 $281,978 $477,441 
The unaudited pro forma financial information is not necessarily indicative of the operating results that would have occurred had the acquisition been completed on January 1, 2022 and is not necessarily indicative of future results of operations of the combined company. The unaudited pro forma financial information gives effect to the acquisition as if the transactions had occurred on January 1, 2022. The unaudited pro forma financial information for the three and nine months ended September 30, 2023 and 2022 is a result of combining the statements of operations of the Company with the pre-acquisition results of BCE-Mach and BCE-Mach II, with pro forma adjustments for revenues and expenses. The unaudited pro forma financial information excludes any cost savings anticipated as a result of the acquisition and the impact of any acquisition-related costs.
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
The unaudited pro forma financial information includes the following adjustments:
For the three months ended September 30, 2023: Reduced depreciation, depletion and accretion-oil and gas of $15.0 thousand, reduced depreciation and amortization-other of $2.2 million, and increased general and administrative expense of $0.4 million.
For the three months ended September 30, 2022: Increased depreciation, depletion and accretion-oil and gas of $0.2 million, reduced depreciation and amortization-other of $2.0 million, and reduced general and administrative expense of $0.9 million.
For the nine months ended September 30, 2023: Reduced depreciation, depletion and accretion-oil and gas of $1.6 million, reduced depreciation and amortization-other of $6.6 million, and increased general and administrative expense of $1.1 million.
For the nine months ended September 30, 2022: Increased depreciation, depletion and accretion-oil and gas of $2.1 million, reduced depreciation and amortization-other of $6.0 million, and reduced general and administrative expense of $2.6 million.
Management believes the estimates and assumptions are reasonable, and the effects of the acquisition are properly reflected.
On June 28, 2023 the Company executed a purchase and sale agreement with Hinkle Oil and Gas, Inc. for the sale of certain oil and gas properties in Oklahoma for $20.0 million, subject to certain adjustments. The transaction closed on August 11, 2023. This purchase was accounted for as an asset acquisition as substantially all of the fair value of acquired assets could be allocated to a single identified asset group of proved oil and natural gas properties.
4. Supplemental Cash Flow Information
Supplemental disclosures to the statement of cash flows are presented below (in thousands):
Nine Months Ended September 30,
20232022
Supplemental disclosure of cash flow information:
Cash paid for interest$5,326 $2,841 
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures$(13,263)$30,475 
Asset retirement cost capitalized$284 $1,310 
Right-of-use assets obtained in exchange for lease liabilities$6,449 $19,820 
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
5. Property and Equipment
The Company’s property and equipment consists of the following (in thousands):
September 30,
2023
December 31,
2022
Oil and natural gas properties
Proved properties$1,018,171 $749,934 
Accumulated depreciation and depletion(225,604)(139,514)
Oil and natural gas properties, net792,567 610,420 
Other property and equipment
Gas gathering system26,510 22,366 
Gas processing plants34,710 33,858 
Water disposal assets24,910 21,029 
Other assets5,016 4,872 
Total other property and equipment91,146 82,125 
Accumulated depreciation, depletion and amortization(13,722)(9,198)
Total other property and equipment, net$77,424 $72,927 
6. Accrued Liabilities
Accrued liabilities consist of the following (in thousands):
September 30,
2023
December 31,
2022
Operating expenses$13,631 $10,198 
Capital expenditures14,965 37,375 
Payroll costs1,943 2,450 
Hedge settlements1,797 898 
Severance and other tax2,370 3,662 
Midstream shipper payable1,280 5,157 
General, administrative, and other788 429 
Total accrued liabilities$36,774 $60,169 
7. Long-Term Debt
On May 19, 2020, BCE-Mach III entered into a credit agreement for a revolving credit facility (the “BCE-Mach III 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 of $400.0 million, subject to commitments of $100.0 million as of September 30, 2023, and matured in May 2026. Outstanding obligations under the credit facility were secured by substantially all of the BCE-Mach III assets. The amount available to be borrowed under the BCE-Mach III Credit Facility was subject to a borrowing base that was redetermined semiannually, each May and November, in an amount determined by the lenders. As of September 30, 2023, and December 31, 2022, there was $91.9 million and $84.9 million, respectively, outstanding under the BCE-Mach III Credit Facility, and the Company was in compliance with all debt covenants. 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 BCE-Mach III Credit Facility was repaid and the Existing Credit Facilities were terminated.

New Credit Facility
On November 10, 2023, Holdco entered into a new revolving credit facility (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.
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
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 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).
8. Derivative Contracts
The Company uses derivative contracts to reduce exposure to fluctuations in commodity prices. These transactions are in the form of fixed price swaps. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. The Company does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.
Under fixed price swap contracts, the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
The Company reports the fair value of derivatives on the balance sheet in derivative contracts assets and derivative contracts liabilities as either current or noncurrent based on the timing of expected future cash flows of individual trades. See Note 9 of our consolidated financial statements for additional information regarding fair value measurements.
The following table summarizes the open financial derivative positions as of September 30, 2023, related to oil production:
PeriodVolume
(Mbbl)
Weighted
Average
Fixed Price
October 2023 – December 2023
700$82.81 
January 2024 – June 2024
508$83.61 
As of September 30, 2023, the Company has no natural gas volumes hedged due to offsetting swap positions of equal volumes.
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Balance Sheet Presentation.    The Company has master netting agreements with all of its derivative counterparties and presents its derivative assets and liabilities with the same counterparty on a net basis on the balance sheet. The following table presents the gross amounts of recognized derivative liabilities, the amounts that are subject to offsetting under master netting arrangements and the net recorded fair values as recognized on the balance sheet (in thousands):
September 30,
2023
December 31,
2022
Derivative contracts – current, gross$3,547 $10,080 
Netting arrangements  
Derivative contracts – current liabilities, net$3,547 $10,080 
There were no recognized derivative assets at September 30, 2023 or December 31, 2022.
Gains and Losses.    The following table presents the settlement and mark-to-market (“MTM”) gains and losses presented as a gain or loss on derivatives in the statement of operations (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Settlements on derivatives$(3,222)$(26,583)$4,308 $(82,705)
MTM gains (losses) on derivatives, net(1,678)24,863 6,534 8,128 
Total gains (losses) on derivative contracts$(4,900)$(1,720)$10,842 $(74,577)
The following table presents the gains and losses recognized on oil and natural gas derivatives in the accompanying statement of operations (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Oil derivatives$(5,759)$15,063 $(1,852)$(27,581)
Natural gas derivatives859 (16,783)12,694 (46,996)
Total gains (losses) on derivative contracts, net$(4,900)$(1,720)$10,842 $(74,577)
9. Fair Value Measurements
Fair value measurement is established by a hierarchy of inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
Level 1 — Quoted prices are available in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2 — Quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets.
Level 3 — Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.
Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Fair Value on a Recurring Basis
Derivative Contracts.    The Company determines the fair value of its derivative contracts using industry standard models that consider various assumptions including current market and contractual prices for the underlying instruments, time value, and nonperformance risk. Substantially all of these inputs are observable in the marketplace throughout the full term of the contract and can be supported by observable data.
Contingent Overriding Royalty Interest.    On January 15, 2020, the Company executed a purchase and sale agreement with Alta Mesa Holdings, LP (“AMH”) for the sale of certain oil and gas assets in Oklahoma and Kingfisher Midstream LLC (“KFM”) for the sale of midstream gathering and processing assets that primarily service the AMH oil and gas assets (the “AMH Acquisition”). On April 2, 2020, the Company entered into the first amendment to the purchase and sale agreement with AMH and KFM. As part of the first amendment to the purchase and sale agreement, consideration of a 5% contingent overriding royalty interest (“the ORRI”) was reserved when certain conditions regarding the market price of oil are met. There was a maximum consideration payable of $25 million related to the ORRI, and the ORRI will be terminated at the earlier of $25 million paid out or three years from the date of the acquisition. Payments relating to this liability for the nine months ended September 30, 2022, were $12.9 million. During the year ending December 31, 2022, the Company reached the maximum consideration of $25 million, therefore no liability remains in relation to the ORRI.
The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2023 and December 31, 2022 (in thousands).
Level 1Level 2Level 3Fair Value
As of September 30, 2023
Liabilities:
Derivative Instruments$ $3,547 $ $3,547 
As of December 31, 2022
Liabilities:
Derivative Instruments$ $10,080 $ $10,080 
Fair Value on a Non-Recurring Basis
The Company determines the initial estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted with proved oil and natural gas properties using the unit of production method.
Fair Value of Other Financial Instruments
The carrying amounts of the Company’s cash and cash equivalents, accounts receivable, accounts payable, revenue payable, accrued interest payable, and other current liabilities approximate fair values due to the short-term maturities of these instruments.
The carrying amount of the New Credit Facility approximates fair value, as the current borrowing base rate does not materially differ from market rates of similar borrowings.
10. Equity Compensation and Deferred Compensation Plan
As part of the Company’s Amended and Restated LLC Agreement as of March 25, 2021, incentive units (“Class B Units”) were issued to certain employees as compensation for services to be rendered to the Company. In determining the appropriate accounting treatment, the Company considered the characteristics of the awards in terms of treatment as stock-based compensation. US GAAP generally requires that all equity awards granted to employees be accounted for at fair value and recognized as compensation cost over the vesting period.
The incentive units are subject to graded vesting over a period of 3 or 4 years (subject to accelerated vesting, as defined by the incentive unit agreement) and a holder of incentive units forfeits unvested incentive units upon ceasing to be
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
an employee of the Company, excluding limited exceptions. The Company recognizes forfeitures as they occur. Holders of incentive units participate in distributions upon the Company meeting a certain requisite financial internal rate of return threshold as defined in the amended LLC agreement.
Determination of the fair value of the awards requires judgements and estimates regarding, among other things, the appropriate methodologies to follow in valuing the award and the related inputs required by those valuation methodologies. For awards granted for the year ended December 31, 2021, the fair value underlying the compensation expense was estimated using the Black-Scholes valuation model with the following primary assumptions:
expected volatility based on the historical volatilities of similar sized companies that most closely represent the Company’s business of 53%;
7 year expected term determined by management based on experience with similarly organized company and expectation of a future sale of the business; and
a risk-free rate based on a U.S Treasury yield curve of 1.40%.
On March 25, 2021, all 20,000 authorized incentive units were granted. Total non-cash compensation cost related to the incentive units was $1.9 million and $5.6 million for the nine months ended September 30, 2023, and 2022, respectively, and $0.6 million and $1.9 million for the three months ended September 30, 2023, and 2022, respectively. As of September 30, 2023, there was $0.7 million in unrecognized compensation cost related to incentive units.
A summary of the incentive unit awards as of September 30, 2023, and 2022 is as follows:
Class B UnitsWeighted Average
 Grant Date
 Fair Value
Unvested at December 31, 202110,333$2,378.80 
Vested(3,665)$2,378.80 
Unvested at September 30, 20226,668$2,378.80 
Unvested at December 31, 20226,668$2,378.80 
Vested(3,667)$2,378.80 
Unvested at September 30, 20233,001$2,378.80 
On October 25, 2023, all unvested Class B Units immediately vested and were exchanged for common units in MNR as part of the Corporate Reorganization. All unrecognized compensation costs were expensed upon the vesting of the Class B Units.
On October 27, 2023, and in connection with the closing of the Offering, MNR adopted a new long-term incentive plan for employees, consultants and directors in connection with the Offering and issued approximately 715,000 phantom units to employees and directors. The phantom unit awards for all employees vest annually (1/3 per year) on the first three anniversaries of the date of the grant, subject to the employee’s continued employment. Within 60 days of the vesting of a phantom unit, the employee will receive a common unit of MNR. Each phantom unit was granted with a corresponding distribution equivalent right, which entitles the participant to receive a payment equal to the total distributions paid by MNR in respect of a common unit of MNR during the time the phantom unit is outstanding.
11. Commitments and Contingencies
Legal Matters.    In the ordinary course of business, the Company may at times be subject to claims and legal actions. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters. The Company did not recognize any material liability as of September 30, 2023, or December 31, 2022. Management does not expect that the impact of such matters will have a materially adverse effect on the Company’s financial position, results of operations or cash flows.
Environmental Matters.    The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.
The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.
12. Leases
Nature of Leases
The Company has operating leases on an office space, various vehicles, and compressors with remaining lease durations in excess of one year. These leases have various expiration dates throughout 2026. The vehicles are used for field operations and leased from third parties. The Company recognizes right-of-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized.
Discount Rate
As most of the Company’s leases do not provide an implicit rate, the Company uses the U.S. 5 Year Treasury Rate in determining the present value of lease payments. Minor changes to the discount rate do not have a material impact to the calculation of the liability, therefore the Company will use this for all asset classes.
Future amounts due under operating lease liabilities as of September 30, 2023, were as follows (in thousands):
Remaining 2023$3,530 
20246,402 
20251,733 
2026628 
2027182 
Total lease payments$12,475 
Less: imputed interest(359)
Total$12,116 
The following table summarizes our total lease costs before amounts are recovered from our joint interest partners, where applicable, for the nine months ended September 30, 2023, and 2022 (in thousands):
Three Months Ended September 30,Nine Months Ended September 30,
2023202220232022
Operating lease cost$3,429 $2,413 $10,047 $5,054 
Short-term lease cost2,600 1,745 7,744 7,297 
Total lease cost$6,029 $4,158 $17,791 $12,351 
The weighted-average remaining lease term as of September 30, 2023, was 1.52 years. The weighted-average discount rate used to determine the operating lease liability as of September 30, 2023, was 4.0%.
13. Members’ Equity
The Company was formed with one member, BCE-Mach Holdings III LLC. Upon formation, the Company consisted of one class of common interests, that were all owned by the member. An amended and restated LLC agreement was executed on February 18, 2020, replacing BCE-Mach Holdings III LLC with BCE-Mach Intermediate Holdings III LLC as the sole initial member. Contributions from the member were $150.0 million for the year ended December 31, 2020. On March 25, 2021, per the amended and restated LLC agreement and the Class A-2 Issuance Agreement, the Company issued 150,000 Class A-1 Units to the initial member, and 1,349 Class A-2 Units to an employee of Mach Resources for service
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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
performed for the Company. Additionally, Class A-2 Units were granted to the employee on a quarterly basis throughout 2021. As of September 30, 2023, there were 3,504 total Class A-2 Units issued to the employee, which have substantially all the same rights as the initial member. In 2022, the Class A-2 Issuance Agreement was updated and there are no additional units being granted to the employee. As part of a long-term incentive plan for certain employees, 20,000 Class B Units were outstanding as of September 30, 2023. The Class B Units represent a non-voting interest in the Company that allows the holder to participate in distributions once the Company’s Class A shares have met a certain requisite financial internal rate of return in accordance with the LLC agreement. On October 25, 2023, in connection with the closing of the Corporate Reorganization, the Class B Units were exchanged for common units in the Company.
Distributions to the members were $101.4 million and $179.8 million for the nine months ended September 30, 2023, and 2022, respectively. Contributions from the members were $20.0 million and $65.0 million for the nine months ended September 30, 2023, and 2022, respectively.
14. Related Parties
Management Services Agreement.    Upon formation of BCE-Mach III, BCE-Mach III entered into a management services agreement (“Original MSA”) with Mach Resources. Under the Original MSA, Mach Resources managed and performed all aspects of oil and gas operations and other general and administrative functions for BCE-Mach III. On a monthly basis, BCE-Mach III distributed funding to Mach Resources for performance under the Original MSA. During the nine months ended September 30, 2023, BCE-Mach III paid Mach Resources $35.0 million, which was inclusive of $3.2 million in management fees. During the nine months ended September 30, 2022, BCE-Mach III paid Mach Resources $27.0 million, which was inclusive of $1.5 million in management fees. During the three months ended September 30, 2023, BCE-Mach III paid Mach Resources $13.9 million, which was inclusive of $1.1 million in management fees. During the three months ended September 30, 2022, BCE-Mach III paid Mach Resources $11.3 million, which was inclusive of $0.5 million in management fees. As of September 30, 2023, BCE-Mach III has $1.4 million in prepaid assets with Mach Resources. As of December 31, 2022, BCE-Mach III owed $0.4 million to Mach Resources. On October 27, 2023, and in connection with the closing of the Offering, MNR entered into a new management services agreement with Mach Resources and terminated the Original MSA.
Contribution Agreement.    On October 25, 2023, MNR entered into a contribution agreement that effected the Corporate Reorganization.
BCE-Stack Development LLC.    BCE-Stack Development LLC (“BCE-Stack”) is an affiliate of the member, and previously was an owner of working and revenue interests in a subset of the Company’s wells. BCE-Stack sold their interests in the wells to the Company on February 28, 2022. Cash paid for the properties was $37.4 million.
BCE-Mach LLC and BCE-Mach II LLC.    BCE-Mach LLC and BCE-Mach II LLC are two related parties that also entered into a management services agreement with Mach Resources. These entities have shared ownership with the Company and operate primarily in different geographical locations than the Company. As of September 30, 2023, the Company owed these entities $0.8 million included in accounts payable. As of December 31, 2022, the Company had receivables from these related parties of approximately $0.7 million included in accounts receivable-joint interest and other.
15. Subsequent Events

Initial Public Offering and Corporate Reorganization

On October 27, 2023, MNR completed the Offering and related reorganization transactions, as discussed in Note 1 of our consolidated financial statements.

Paloma Acquisition

On November 10, 2023, MNR signed an agreement with Paloma Partners IV, LLC, to acquire certain interests in oil and gas properties, rights, and related assets located in Oklahoma for total cash consideration of $815.0 million, subject to customary closing adjustments. The acquisition is expected to close in December 2023, with funding provided by new debt financing in the form of a $825.0 million senior secured term loan.

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BCE-MACH III LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
New Credit Facility
On November 10, 2023, Holdco entered into the New Credit Facility with MidFirst Bank and the Existing Credit Facilities were terminated, as discussed in Note 7 of our consolidated financial statements.
Derivative contracts
Subsequent to September 30, 2023 the Company entered into the following derivative contracts:

PeriodVolume
Weighted
Average
Fixed Price
OilMbbl
20241,140$73.95 
20251,130$71.80 
Natural GasMmbtu
202423,320$3.34 
202518,410$4.08 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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
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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
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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
Three Months Ended
September 30,
Nine Months Ended
September 30,
($ in thousands)2023202220232022
Net income$83,485 $172,220 $252,988 $394,850 
Interest expense2,054 1,317 5,843 3,193 
Interest income(387)— (881)— 
Depreciation, depletion, amortization and accretion33,035 27,663 93,923 59,045 
Unrealized (gain) loss on derivative settlements1,678 (24,863)(6,534)(8,128)
Equity-based compensation expense 647 1,882 1,941 5,646 
(Gain) loss on sale of assets— — (1)22 
Adjusted EBITDA$120,512 $178,219 $347,279 $454,628 
Net income$83,485 $172,220 $252,988 $394,850 
Interest expense2,054 1,317 5,843 3,193 
Interest income(387)— (881)— 
Depreciation, depletion, amortization and accretion33,035 27,663 93,923 59,045 
Unrealized (gain) loss on derivative settlements1,678 (24,863)(6,534)(8,128)
Equity-based compensation expense647 1,882 1,941 5,646 
(Gain) loss on sale of assets— — (1)22 
Settlement of asset retirement obligations(366)— (445)(49)
Cash interest expense(2,023)(1,223)(5,611)(2,913)
Cash interest income387 — 881 — 
Development costs(66,052)(82,389)(258,944)(197,763)
Settlement of contingent consideration— (4,814)— (12,925)
Change in accrued realized derivative settlements1,183 (5,168)899 (2,802)
Cash available for distribution$53,641 $84,625 $84,059 $238,176 
Net cash provided by operating activities$106,822 $170,366 $381,967 $398,302 
Changes in operating assets and liabilities12,871 (3,352)(38,964)37,637 
Development costs(66,052)(82,389)(258,944)(197,763)
Cash available for distribution$53,641 $84,625 $84,059 $238,176 
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:
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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.
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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.

Three Months Ended September 30,Change
($ in thousands)20232022AmountPercent
Revenues:
Oil$113,112 $123,583 (10,471)(8)%
Natural gas36,489 104,921 (68,432)(65)%
Natural gas liquids17,105 29,927 (12,822)(43)%
Total oil, natural gas, and NGL sales166,706 258,431 (91,725)(35)%
Gain (loss) on oil and natural gas derivatives, net(4,900)(1,720)(3,180)185 %
Midstream revenue6,683 12,045 (5,362)(45)%
Product sales6,900 26,988 (20,088)(74)%
Total revenues$175,389 $295,744 $(120,355)(41)%
Average Sales Price(1):
Oil ($/Bbl)$81.31 $92.11 $(10.80)(12)%
Natural gas ($/Mcf)$2.51 $7.65 $(5.14)(67)%
NGL ($/Bbl)$23.37 $39.06 $(15.69)(40)%
Total ($/Boe) – before effects of realized derivatives$36.69 $58.81 $(22.12)(38)%
Total ($/Boe) – after effects of realized derivatives$35.98 $52.76 $(16.78)(32)%
Net Production Volumes:
Oil (MBbl)1,3911,34249%
Natural gas (MMcf)14,52713,718809%
NGL (MBbl)732766(34)(4 %)
Total (MBoe)4,5444,394150%
Average daily total volumes (MBoe/d)49.3947.761.63%

____________
(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.
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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 $2.5 million is due to decreased saltwater gathering and disposal revenue.
Operating expenses
The following table summarizes the Company’s expenses for the periods indicated and includes a presentation of certain expenses on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:
Three Months Ended September 30,Change
($ in thousands)20232022AmountPercent
Operating Expenses:
Gathering and processing expense$7,962 $15,147 $(7,185)(47 %)
Lease operating expense$28,879 $28,431 $448 %
Midstream operating expense$2,725 $4,029 $(1,304)(32 %)
Cost of product sales$6,024 $25,355 $(19,331)(76 %)
Production taxes$7,660 $14,484 $(6,824)(47 %)
Depreciation, depletion, amortization and accretion expense – oil and natural gas$31,277 $26,446 $4,831 18 %
Depreciation and amortization expense – other$1,758 $1,217 $541 44 %
General and administrative$5,360 $5,799 $(439)(8)%
Operating Expenses ($/Boe)
Gathering and processing expense$1.75 $3.45 $(1.70)(49 %)
Lease operating expense$6.36 $6.47 $(0.11)(2 %)
Production taxes (% of oil, natural gas and NGL sales)4.6 %5.6 %(1.0)%(18 %)
Depreciation, depletion, amortization and accretion expense – oil and natural gas$6.88 $6.02 $0.86 14 %
Depreciation and amortization expense – other$0.39 $0.28 $0.11 39 %
General and administrative$1.18 $1.32 $(0.14)(11)%
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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.
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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.
Nine Months Ended September 30,Change
($ in thousands)20232022AmountPercent
Revenues:
Oil$321,427 $342,708 (21,281)(6)%
Natural gas106,069 234,815 (128,746)(55)%
Natural gas liquids51,823 89,350 (37,527)(42)%
Total oil, natural gas, and NGL sales479,319 666,873 (187,554)(28)%
Gain (loss) on oil and natural gas derivatives, net10,842 (74,577)85,419 (115 %)
Midstream revenue20,001 31,929 (11,928)(37)%
Product sales24,321 74,948 (50,627)(68)%
Total revenues$534,483 $699,173 $(164,690)(24)%
Average Sales Price(1):
Oil ($/Bbl)$77.42 $98.40 $(20.98)(21)%
Natural gas ($/Mcf)$2.54 $6.85 $(4.31)(63)%
NGL ($/Bbl)$24.62 $42.79 $(18.17)(42)%
Total ($/Boe) – before effects of realized derivatives$36.30 $59.09 $(22.79)(39)%
Total ($/Boe) – after effects of realized derivatives$36.63 $51.76 $(15.13)(29)%
Net Production Volumes:
Oil (MBbl)4,1513,48366819 %
Natural gas (MMcf)41,68534,2877,39822 %
NGL (MBbl)2,1052,08817%
Total (MBoe)13,20411,2851,91917 %
Average daily total volumes (MBoe/d)48.3741.347.0317 %
____________
(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
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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 $5.6 million is due to decreased saltwater gathering and disposal revenue.
Operating expenses
The following table summarizes the Company’s expenses for the periods indicated and includes a presentation of certain expenses on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:
Nine Months Ended September 30,Change
($ in thousands)20232022AmountPercent
Operating Expenses:
Gathering and processing expense$25,472 $35,959 $(10,487)(29 %)
Lease operating expense$89,494 $68,023 $21,471 32 %
Midstream operating expense$8,263 $11,006 $(2,743)(25 %)
Cost of product sales$21,599 $70,313 $(48,714)(69 %)
Production taxes$23,186 $37,159 $(13,973)(38 %)
Depreciation, depletion, amortization and accretion expense – oil and natural gas$89,372 $55,820 $33,552 60 %
Depreciation and amortization expense – other$4,551 $3,225 $1,326 41 %
General and administrative$15,265 $19,447 $(4,182)(22)%
Operating Expenses ($/Boe)
Gathering and processing expense$1.93 $3.19 $(1.26)(39 %)
Lease operating expense$6.78 $6.03 $0.75 12 %
Production taxes (% of oil, natural gas and NGL sales)4.8 %5.6 %(0.8)%(14 %)
Depreciation, depletion, amortization and accretion expense – oil and natural gas$6.77 $4.95 $1.82 37 %
Depreciation and amortization expense – other$0.34 $0.29 $0.05 17 %
General and administrative$1.16 $1.72 $(0.56)(33)%
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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.
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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.
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Cash flows
The following table summarizes the Company’s cash flows for the periods indicated:
Nine Months Ended September 30,
(in thousands)20232022
Net cash provided by operating activities$381,967 $398,302 
Net cash used in investing activities$(277,893)$(292,469)
Net cash used in financing activities$(74,754)$(115,736)
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
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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.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
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
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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.
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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.
Item 4. Controls and Procedures
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.

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PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. The Company is not currently a party to any material legal proceedings. In addition, the Company is not aware of any material legal proceedings contemplated to be brought against the Company.
The Company, as an owner and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.
The Company is not aware of any environmental claims existing as of September 30, 2023. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered on the Company’s oil and gas properties.
Item 1A. Risk Factors
There have been no material changes to the Company’s “Risk Factors” as described in the Registration Statement.
Item 2. Unregistered Sales of Equity Securities, Use of Proceeds, and Issuer Purchases of Equity Securities
Unregistered Sale of Equity Securities
On October 25, 2023, MNR underwent the 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, (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 referenced issuances did not involve any underwriters, underwriting discounts or commissions, or any public offering and we believe such issuances are exempt from the registration requirements of the Securities Act by virtue of Section 4(a)(2) thereof and/or Regulation D promulgated thereunder.
Use of Proceeds
On October 24, 2023, the Registration Statement (File No. 333-274662) was declared effective by the SEC for the Offering pursuant to which MNR registered and sold an aggregate of 10,000,000 common units at a price of $19.00 per common unit to the public. The sale of the common units resulted in gross proceeds of $190.0 million to MNR and net proceeds of $170.0 million, after deducting underwriting fees and offering expenses of $20.0 million.
MNR used $103.7 million of the proceeds to pay down the Existing Credit Facilities of its operating subsidiaries and $66.3 million of the proceeds to purchase 3,750,000 common units from the existing common unit owners on a pro rata basis.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.
Item 5. Other Information
During the three months ended September 30, 2023, none of our directors or “officers” (as such term is defined in Rule 16(a)-1(f) under the Exchange Act) adopted or