10-Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2024

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-39919

MONTAUK RENEWABLES, INC.

(Exact name of registrant as specified in its charter)


Delaware	85-3189583
(State or Other Jurisdiction of Incorporation or Organization)	(IRS Employer Identification No.)

5313 Campbells Run Road, Suite 200 Pittsburgh, Pennsylvania	15205
(Address of Principal Executive Offices)	(Zip Code)

(412) 747-8700

(Registrant’s Telephone Number, Including Area Code)

N/A

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

    Title of each class
 
    Trading symbol(s)
 
    Name of each exchange on which registered

    Common Stock, par value $0.01 per share

    MNTK

    The Nasdaq Capital Market

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 ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:


Large accelerated filer	☐	Accelerated filer	☒

Non-accelerated filer	☐	Smaller reporting company	☐

		Emerging growth company	☒

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. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The number of outstanding shares of the registrant’s common stock on November 8, 2024 was 143,367,622 shares.

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TABLE OF CONTENTS


		Page

PART I FINANCIAL INFORMATION		6

ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	6

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	27

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	49

ITEM 4.	CONTROLS AND PROCEDURES	49

PART II OTHER INFORMATION		50

ITEM 1.	LEGAL PROCEEDINGS	50

ITEM 1A.	RISK FACTORS	50

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	50

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	50

ITEM 4.	MINE SAFETY DISCLOSURES	50

ITEM 5.	OTHER INFORMATION	50

ITEM 6.	EXHIBITS	51

SIGNATURES		52

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Glossary of Key Terms

This Quarterly Report on Form 10-Q uses several terms of art that are specific to our industry and business. For the convenience of the reader, a glossary of such terms is provided here. Unless we otherwise indicate, or unless the context requires otherwise, any references in this Quarterly Report on Form 10-Q to:

•

“ADG” refers to anaerobic digested gas.

•

“CARB” refers to the California Air Resource Board.

•

“CNG” refers to compressed natural gas.

•

“CI” refers to carbon intensity.

•

“D3” refers to cellulosic biofuel with a 60% GHG reduction requirement.

•

“EPA” refers to the U.S. Environmental Protection Agency.

•

“Environmental Attributes” refer to federal, state and local government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, rebates, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy.

•

“FERC” refers to the U.S. Federal Energy Regulatory Commission.

•

“GHG” refers to greenhouse gases.

•

“JSE” refers to the Johannesburg Stock Exchange.

•

“LCFS” refers to Low Carbon Fuel Standard.

•

“LFG” refers to landfill gas.

•

“MMBtu” refers to Metric Million British Thermal Unit.

•

“PPAs” refers to power purchase agreements.

•

“RECs” refers to Renewable Energy Credits.

•

“Renewable Electricity” or "REG" refers to electricity generated from renewable sources.

•

“RFS” refers to the EPA’s Renewable Fuel Standard.

•

“RINs” refers to Renewable Identification Numbers.

•

“RNG” refers to renewable natural gas.

•

“RVOs” refers to renewable volume obligations.

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Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of U.S. federal securities laws that involve substantial risks and uncertainties. All statements other than statements of historical or current fact included in this report are forward-looking statements. Forward-looking statements refer to our current expectations and projections relating to our financial condition, results of operations, plans, objectives, strategies, future performance, and business. Forward-looking statements may include words such as “anticipate,” “assume,” “believe,” “can have,” “contemplate,” “continue,” “strive,” “aim,” “could,” “design,” “due,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “likely,” “may,” “might,” “objective,” “plan,” “predict,” “project,” “potential,” “seek,” “should,” “target,” “will,” “would,” and other words and terms of similar meaning in connection with any discussion of the timing or nature of future operational performance or other events. For example, all statements we make relating to our future results of operations, financial condition, expectations and plans, including those related to the Montauk Ag project in North Carolina, the Second Apex RNG Facility, the Blue Granite RNG Facility, the Bowerman RNG Facility, the delivery of biogenic carbon dioxide volumes to European Energy, the Emvolon collaboration and pilot project, the resolution of gas collection issues at the McCarty facility, the delays and cancellations of landfill host wellfield expansion projects, the mitigation of wellfield extraction environmental factors at the Rumpke and Apex facilities, how we may monetize RNG production, and weather-related anomalies are forward-looking statements. All forward-looking statements are subject to risks and uncertainties that may cause actual results to differ materially from those that we expect and, therefore, you should not unduly rely on such statements. The risks and uncertainties that could cause those actual results to differ materially from those expressed or implied by these forward-looking statements include but are not limited to:

•

our ability to develop and operate new renewable energy projects, including with livestock farms, and related challenges associated with new projects, such as identifying suitable locations and potential delays in acquisition financing, construction, and development;

•

reduction or elimination of government economic incentives to the renewable energy market, whether as a result of the new presidential administration or otherwise;

•

the inability to complete strategic development opportunities;

•

widespread manmade, natural and other disasters (including severe weather events), health emergencies, dislocations, geopolitical instabilities or events, terrorist activities, international hostilities, government shutdowns, political elections, security breaches, cyberattacks or other extraordinary events that impact general economic conditions, financial markets and/or our business and operating results;

•

taxes, tariffs, duties or other assessments on equipment necessary to generate renewable energy or continued inflation could raise our operating costs or increase the construction costs of our existing or new projects;

•

rising interest rates could increase the borrowing costs of future indebtedness;

•

the potential failure to attract and retain qualified personnel of the Company or a possible increased reliance on third-party contractors as a result, and the potential unenforceability of non-compete clauses with our employees;

•

the length of development and optimization cycles for new projects, including the design and construction processes for our renewable energy projects;

•

dependence on third parties for the manufacture of products and services and our landfill operations;

•

the quantity, quality and consistency of our feedstock volumes from both landfill and livestock farm operations;

•

reliance on interconnections with and access to electric utility distribution and transmission facilities and gas transportation pipelines for our Renewable Natural Gas and Renewable Electricity Generation segments;

•

our ability to renew pathway provider sharing arrangements at historical counterparty share percentages;

•

our projects not producing expected levels of output;

•

potential benefits associated with the combustion-based oxygen removal condensate neutralization technology;

•

concentration of revenues from a small number of customers and projects;

•

our outstanding indebtedness and restrictions under our credit facility;

•

our ability to extend our fuel supply agreements prior to expiration;

•

our ability to meet milestone requirements under our PPAs;

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•

existing regulations and changes to regulations and policies that effect our operations, whether as a result of the new presidential administration or otherwise;

•

expected benefits from the extension of the Production Tax Credit and other tax credit benefits under the Inflation Reduction Act of 2022;

•

decline in public acceptance and support of renewable energy development and projects, or our inability to appropriately address environmental, social and governance targets, goals, commitments or concerns, including climate-related disclosures;

•

our expectations regarding Environmental Attribute volume requirements and prices and commodity prices;

•

our expectations regarding the period during which we qualify as an emerging growth company under the Jumpstart Our Business Startups Act (“JOBS Act”);

•

our expectations regarding future capital expenditures, including for the maintenance of facilities;

•

our expectations regarding the use of net operating losses before expiration;

•

our expectations regarding more attractive CI scores by regulatory agencies for our livestock farm projects;

•

market volatility and fluctuations in commodity prices and the market prices of Environmental Attributes and the impact of any related hedging activity;

•

regulatory changes in federal, state and international environmental attribute programs and the need to obtain and maintain regulatory permits, approvals, and consents;

•

profitability of our planned livestock farm projects;

•

sustained demand for renewable energy;

•

potential liabilities from contamination and environmental conditions;

•

potential exposure to costs and liabilities due to extensive environmental, health and safety laws;

•

impacts of climate change, changing weather patterns and conditions, and natural disasters;

•

failure of our information technology and data security systems;

•

increased competition in our markets;

•

continuing to keep up with technology innovations;

•

concentrated stock ownership by a few stockholders and related control over the outcome of all matters subject to a stockholder vote; and

•

other risks and uncertainties detailed in the section titled “Risk Factors” in our latest Annual Report on Form 10-K and as otherwise disclosed in our filings with the SEC.

We make many of our forward-looking statements based on our operating budgets and forecasts, which are based upon detailed assumptions. While we believe that our assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors, and it is impossible for us to anticipate all factors that could affect our actual results.

All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements as well as others made in our other Securities and Exchange Commission (“SEC”) filings and public communications. You should evaluate all forward-looking statements made by us in the context of these risks and uncertainties. See the “Risk Factors” section in our latest Annual Report on Form 10-K and our other filings with the SEC.

We caution you that the risks and uncertainties identified by us may not be all of the factors that are important to you. Furthermore, the forward-looking statements included in this report are made only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statement as a result of new information, future events, or otherwise, except as required by law.

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PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS


	Page
Montauk Renewables, Inc.
Unaudited condensed consolidated financial statements
Unaudited consolidated balance sheets	7
Unaudited consolidated statements of operations	8
Unaudited consolidated statements of stockholders’ equity	9
Unaudited consolidated statements of cash flows	10
Condensed notes to unaudited consolidated financial statements	11

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MONTAUK RENEWABLES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data):


	as of September 30,			as of December 31,
ASSETS	2024			2023
Current assets:
Cash and cash equivalents	$	54,973		$	73,811
Accounts and other receivables		19,217			12,752
Current restricted cash		82			8
Current portion of derivative instruments		428			785
Prepaid expenses and other current assets		4,576			2,819
Total current assets	$	79,276		$	90,175
Non-current restricted cash	$	374		$	423
Property, plant and equipment, net		249,845			214,289
Goodwill and intangible assets, net		18,460			18,421
Deferred tax assets		33			2,076
Non-current portion of derivative instruments		179			470
Operating lease right-of-use assets		4,054			4,313
Finance lease right-of-use assets		129			36
Related party receivable		10,168			10,138
Other assets		11,600			9,897
Total assets	$	374,118		$	350,238

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	10,154		$	7,916
Accrued liabilities		15,763			12,789
Income tax payable		1,584			313
Current portion of operating lease liability		457			420
Current portion of finance lease liability		71			26
Current portion of long-term debt		10,868			7,886
Total current liabilities	$	38,897		$	29,350
Long-term debt, less current portion	$	46,719		$	55,614
Non-current portion of operating lease liability		3,849			4,133
Non-current portion of finance lease liability		58			10
Asset retirement obligations		6,226			5,900
Other liabilities		3,032			4,992

Total liabilities	$	98,781		$	99,999

Commitments and contingencies (Note 20)

STOCKHOLDERS’ EQUITY

Common stock, $0.01 par value, authorized 690,000,000 shares; 143,732,811 shares issued at September 30, 2024 and December 31, 2023; 142,567,055 and 141,986,189 shares outstanding at September 30, 2024 and December 31, 2023, respectively	$	1,425		$	1,420
Treasury stock, at cost, 1,315,403 and 984,762 shares September 30, 2024 and December 31, 2023, respectively		(12,882	)		(11,173	)
Additional paid-in capital		222,994			214,378
Retained earnings		63,800			45,614
Total stockholders' equity	$	275,337		$	250,239
Total liabilities and stockholders' equity	$	374,118		$	350,238

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these statements.

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(in thousands, except for share and per share data):


	For the three months ended September 30,						For the nine months ended September 30,
	2024			2023			2024			2023
Total operating revenues	$	65,917		$	55,688		$	148,042		$	128,097

Operating expenses:
Operating and maintenance expenses		15,484			14,212			48,596			43,614
General and administrative expenses		10,037			7,848			28,202			26,069
Royalties, transportation, gathering and production fuel		11,107			11,450			26,702			25,588
Depreciation, depletion and amortization		6,048			5,346			17,305			15,792
Impairment loss		533			51			1,232			777
Transaction costs		—			—			61			86
Total operating expenses	$	43,209		$	38,907		$	122,098		$	111,926
Operating income	$	22,708		$	16,781		$	25,944		$	16,171

Other expenses (income):
Interest expense	$	1,835		$	1,295		$	4,285		$	3,681
Other income		(140	)		(256	)		(1,249	)		(340	)
Total other expenses	$	1,695		$	1,039		$	3,036		$	3,341
Income before income taxes	$	21,013		$	15,742		$	22,908		$	12,830

Income tax expense		3,965			2,808			4,722			2,681
Net income	$	17,048		$	12,934		$	18,186		$	10,149

Income per share:
Basic	$	0.12		$	0.09		$	0.13		$	0.07
Diluted	$	0.12		$	0.09		$	0.13		$	0.07

Weighted-average common shares outstanding:
Basic		142,410,940			141,717,612			142,156,540			141,661,790
Diluted		142,620,332			142,299,875			142,331,541			142,000,827

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these statements.

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

(in thousands, except share data):


	Common stock				Treasury stock
	Shares		Amount		Shares		Amount			Additional paid-in capital		Retained earnings		Total equity
Balance at June 30, 2024		142,186,722	$	1,422		1,069,627	$	(11,570	)	$	218,717	$	46,752	$	255,321
Issuance of common stock		380,333		3		—		—			—		—		3
Treasury stock		—		—		245,776		(1,312	)		—		—		(1,312	)
Net income		—		—		—		—			—		17,048		17,048
Stock-based compensation		—		—		—		—			4,277		—		4,277
Balance at September 30, 2024		142,567,055	$	1,425		1,315,403	$	(12,882	)	$	222,994	$	63,800	$	275,337

Balance at June 30, 2023		141,633,417	$	1,416		971,306	$	(11,051	)	$	209,555	$	27,881	$	227,801
Vesting of stock awards		215,165		—		—		—			—		—		—
Net income		—		—		—		—			—		12,934		12,934
Stock-based compensation		—		—		—		—			2,500		—		2,500
Balance at September 30, 2023		141,848,582	$	1,416		971,306	$	(11,051	)	$	212,055	$	40,815	$	243,235

Balance at December 31, 2023		141,986,189	$	1,420		984,762	$	(11,173	)	$	214,378	$	45,614	$	250,239
Issuance of common stock		580,866		5		—		—			—		—		5
Treasury stock		—		—		330,641		(1,709	)		—		—		(1,709	)
Net income		—		—		—		—			—		18,186		18,186
Stock-based compensation		—		—		—		—			8,616		—		8,616
Balance at September 30, 2024		142,567,055	$	1,425		1,315,403	$	(12,882	)	$	222,994	$	63,800	$	275,337

Balance at December 31, 2022		141,633,417	$	1,416		971,306	$	(11,051	)	$	206,060	$	30,666	$	227,091
Vesting of stock awards		215,165		—		—		—			—		—		—
Net income		—		—		—		—			—		10,149		10,149
Stock-based compensation		—		—		—		—			5,995		—		5,995
Balance at September 30, 2023		141,848,582	$	1,416		971,306	$	(11,051	)	$	212,055	$	40,815	$	243,235

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these statements.

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands):


	For the nine months ended September 30,
	2024			2023
Cash flows from operating activities:
Net income	$	18,186		$	10,149
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		17,305			15,792
Provision for deferred income taxes		2,044			1,786
Stock-based compensation		8,616			5,995
Derivative mark-to-market adjustments and settlements		648			(160	)
Net loss on sale of assets		72			37
(Decrease) increase in earn-out liability		(1,744	)		959
Accretion of asset retirement obligations		333			304
Liabilities associated with properties sold		(225	)		—
Amortization of debt issuance costs		270			276
Impairment loss		1,232			777
Changes in operating assets and liabilities:
Accounts and other receivables and other current assets		(9,997	)		(18,123	)
Accounts payable and other accrued expenses		6,331			1,795
Net cash provided by operating activities	$	43,071		$	19,587
Cash flows from investing activities:
Capital expenditures	$	(53,334	)	$	(45,406	)
Asset acquisition		(820	)		—
Cash collateral deposits		25			2
Net cash used in investing activities	$	(54,129	)	$	(45,404	)
Cash flows from financing activities:
Repayments of long-term debt	$	(6,000	)	$	(6,000	)
Common stock issuance		5			—
Treasury stock purchase		(1,709	)		—
Finance lease payments		(51	)		(54	)
Net cash used in financing activities	$	(7,755	)	$	(6,054	)
Net decrease in cash and cash equivalents and restricted cash	$	(18,813	)	$	(31,871	)
Cash and cash equivalents and restricted cash at beginning of period	$	74,242		$	105,606
Cash and cash equivalents and restricted cash at end of period	$	55,429		$	73,735
Reconciliation of cash, cash equivalents, and restricted cash at end of period:
Cash and cash equivalents	$	54,973		$	73,304
Restricted cash and cash equivalents - current		82			22
Restricted cash and cash equivalents - non-current		374			409
	$	55,429		$	73,735

Supplemental cash flow information:
Cash paid for interest	$	3,895		$	3,713
Cash paid for income taxes		1,407			1,034
Accrual for purchase of property, plant and equipment included in accounts payable and accrued liabilities		6,928			2,595

The accompanying notes to the unaudited condensed consolidated financial statements are an integral part of these statements.

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MONTAUK RENEWABLES, INC.

CONDENSED NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(dollars in thousands, except per-share amounts)

NOTE 1 – DESCRIPTION OF BUSINESS

Operations and organization

Montauk Renewables’ Business

Montauk Renewables, Inc. (the “Company” or “Montauk Renewables”) is a renewable energy company specializing in the management, recovery and conversion of biogas into Renewable Natural Gas (“RNG”). The Company captures methane, preventing it from being released into the atmosphere, and converts it into either RNG or electrical power for the electrical grid (“Renewable Electricity Generation” or "REG"). The Company, headquartered in Pittsburgh, Pennsylvania, has more than 30 years of experience in the development, operation and management of landfill methane-fueled renewable energy projects. The Company has operations at 14 projects and ongoing development projects located in California, Idaho, Ohio, Oklahoma, Pennsylvania, North Carolina, South Carolina and Texas. The Company sells RNG and Renewable Electricity, taking advantage of Environmental Attribute premiums available under federal and state policies that incentivize their use.

Two of the Company’s key revenue drivers are sales of produced gas and sales of Renewable Identification Numbers (“RINs”) to fuel blenders. The Renewable Fuel Standard (“RFS”) is an Environmental Protection Agency (“EPA”) administered federal law that requires transportation fuel to contain a minimum volume of renewable fuel. RNG derived from landfill methane, agricultural digesters and wastewater treatment facilities used as a vehicle fuel qualifies as a D3 (cellulosic biofuel with a 60% greenhouse gas reduction requirement) RIN. The RINs are compliance units for fuel blenders that were created by the RFS program in order to reduce greenhouse gases and imported petroleum into the United States.

An additional program utilized by the Company is the Low Carbon Fuel Standard (“LCFS”). This is state specific and is designed to stimulate the use of low-carbon fuels. To the extent that RNG from the Company’s facilities is used as a transportation fuel in states that have adopted an LCFS program, it is eligible to receive an Environmental Attribute additional to the RIN value under the federal RFS.

Another key revenue driver is the sale of generated electricity and the associated environmental premiums related to electricity sales. The Company’s electric facilities are designed to conform to and monetize various state renewable portfolio standards requiring a percentage of the electricity produced in that state to come from a renewable resource. Such premiums are in the form of Renewable Energy Credits (“RECs”). The Company’s largest electric facility, located in California, receives revenue for the monetization of RECs as a part of a purchase power agreement.

Collectively, the Company benefits from federal and state government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy, as Environmental Attributes.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions of the SEC on Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and disclosures required by GAAP for complete financial statements. In the opinion of management, the unaudited condensed consolidated financial statements include all adjustments necessary, which are of a normal and recurring nature, for the fair presentation of the Company’s financial position and of the results of operations and cash flows for the periods presented. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2023 included in the Company’s Annual Report on Form 10-K filed with the SEC on March 14, 2024 (the “2023 Annual Report”). The results of operations for the three and nine months ended September 30, 2024 in this report are not necessarily indicative of the results that may be expected for any other interim period or for the full year. The balance sheet at December 31, 2023, has been derived from the audited financial statements as of that date. For further information, refer to the Company’s audited financial statements and notes thereto included for the year ended December 31, 2023 in the 2023 Annual Report.

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Segment Reporting

The Company reports segment information in three segments: RNG, Renewable Electricity Generation and Corporate. This is consistent with the internal reporting provided to the chief operating decision maker who evaluates operating results and performance. The aforementioned business services and offerings described in Note 1 are grouped and defined by management as two distinct operating segments: RNG and Renewable Electricity Generation. The Corporate segment primarily consists of general and administrative expenses not allocated to RNG and Renewable Electricity Generation. Below is a description of the Company’s segments and other activities.

The RNG segment represents the sale of gas sold at fixed-price contracts, counterparty shares of RNG volumes and applicable Environmental Attributes. This business unit represents the majority of the revenues generated by the Company. The Renewable Electricity Generation segment represents the sale of generated electricity and applicable Environmental Attributes.

Corporate relates to additional discrete financial information for the corporate function. It is primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment. As such, the Corporate segment is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.

Use of Estimates

The preparation of financial statements, in conformity with 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. Actual results could differ from those estimates.

Recently Issued Accounting Standards

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848), which provides optional expedients and exceptions to the current guidance on contract modifications and hedging relationships to ease the financial reporting burdens of the expected market transition from London Interbank Offered Rate (“LIBOR”) and other interbank offered rates to alternative reference rates. The guidance was effective upon issuance and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022. The FASB included a sunset provision within Topic 848 based on expectations of when the LIBOR would cease being published. The sunset provision has been amended from December 31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. The Company’s current debt agreement bears interest at the Bloomberg Short-Term Bank Yield Index Rate, "BSBY", plus an applicable margin. The BSBY index will cease on November 15, 2024, and the current debt agreement has been amended to utilize the Secured Overnight Financing Rate Index, "SOFR", plus an applicable margin.

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segments. The amendments in 2023-07 aim to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. ASU 2023-07 is effective for the Company's Annual Report on Form 10-K for the year ended December 31, 2024, and subsequent interim periods, with early adoption permitted. Other than enhanced disclosures, the Company does not expect a material impact from the adoption of this standard on its consolidated financial statements.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments in 2023-09 aim to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is effective for the Company's Annual Report on Form 10-K for the year ended December 31, 2025, with early adoption permitted. Other than enhanced disclosures, the Company does not expect a material impact from the adoption of this standard on its consolidated financial statements.

NOTE 3 – ASSET IMPAIRMENT

The Company recorded an impairment loss of $533 and $51 for the three months ended September 30, 2024 and 2023, respectively and $1,232 and $777 for the nine months ended September 30, 2024 and 2023, respectively. On February 18, 2024, for one of its REG sites, the Company entered into a bill of sale, assignment and assumption agreement to sell its rights to the existing fuel supply agreement and property back to the site host in advance of the fuel supply agreement termination date and received $1,000 in proceeds. The effective date of the sale, assignment and assumption agreement is October 1, 2024. The Company elected to cease operations prior to the assignment date and consequently the remaining book value of long lived assets and intangibles were impaired for $312. The remaining impairments included $591 for various RNG equipment that was deemed obsolete or inoperable for current operations and $329 in REG assets that were impacted under initial startup testing for one of its REG construction work in progress

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sites. The 2023 impairments were for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and recorded in the Company's RNG segment.

NOTE 4 – REVENUES FROM CONTRACTS WITH CUSTOMERS

The Company’s revenues are comprised of renewable energy and related Environmental Attribute sales provided under short and medium term contracts with its customers. All revenue is recognized when (or as) the Company satisfies its performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product or service to its customer either when (or as) its customer obtains control of the product or service. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. The Company allocates the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract.

Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring its products or services. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred by the customer following the transfer of control of the commodities sold. To the extent applicable, sales, value add and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.

The Company’s performance obligations related to the sale of renewable energy (i.e. RNG and Renewable Electricity Generation) are generally satisfied over time. Revenue related to the sale of renewable energy is generally recognized over time using an output based upon the product quantity delivered to the customer. This measure is used to best depict the Company’s performance to date under the terms of the contract. Revenue from products transferred to customers over time accounted for approximately 16% and 18% of revenue for the three months ended September 30, 2024 and 2023, respectively, and 20% and 24% of revenue for the nine months ended September 30, 2024 and 2023, respectively.

The nature of the Company’s contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of the Company’s influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the contracts is considered fully constrained.

The Company’s performance obligations related to the sale of Environmental Attributes are generally satisfied at a point in time and were approximately 84% and 82% of revenue for the three months ended September 30, 2024 and 2023, respectively, and 80% and 76% for the nine months ended September 30, 2024 and 2023, respectively. The Company recognizes Environmental Attribute revenue at the point in time in which the customer obtains control of the Environmental Attributes, which is generally when the title of the Environmental Attribute passes to the customer upon delivery. In limited cases, title does not transfer to the customer and revenue is not recognized until the customer has accepted the Environmental Attributes.

The following tables display the Company’s disaggregated revenue by major source based on product type and timing of transfer of goods and services for the three and nine months ended September 30, 2024 and 2023:


	Three months ended September 30, 2024
	Goods transferred at a point in time		Goods transferred over time		Total
Major goods/Service line:
Natural gas commodity	$	333	$	8,100	$	8,433
Natural gas environmental attributes		53,206		—		53,206
Electric commodity		—		2,402		2,402
Electric environmental attributes		1,876		—		1,876
	$	55,415	$	10,502	$	65,917
Operating segment:
RNG	$	53,539	$	8,100	$	61,639
REG		1,876		2,402		4,278
	$	55,415	$	10,502	$	65,917

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	Three months ended September 30, 2023
	Goods transferred at a point in time		Goods transferred over time		Total
Major goods/Service line:
Natural gas commodity	$	232	$	7,060	$	7,292
Natural gas environmental attributes		43,612		—		43,612
Electric commodity		—		2,821		2,821
Electric environmental attributes		1,963		—		1,963
	$	45,807	$	9,881	$	55,688
Operating segment:
RNG	$	43,844	$	7,060	$	50,904
REG		1,963		2,821		4,784
	$	45,807	$	9,881	$	55,688


	Nine months ended September 30, 2024
	Goods transferred at a point in time		Goods transferred over time		Total
Major goods/Service line:
Natural gas commodity	$	1,023	$	22,024	$	23,047
Natural gas environmental attributes		111,281		—		111,281
Electric commodity		—		7,983		7,983
Electric environmental attributes		5,731		—		5,731
	$	118,035	$	30,007	$	148,042
Operating segment:
RNG	$	112,304	$	22,024	$	134,328
REG		5,731		7,983		13,714
	$	118,035	$	30,007	$	148,042


	Nine months ended September 30, 2023
	Goods transferred at a point in time		Goods transferred over time		Total
Major goods/Service line:
Natural gas commodity	$	638	$	21,931	$	22,569
Natural gas environmental attributes		91,630		—		91,630
Electric commodity		—		8,244		8,244
Electric environmental attributes		5,654		—		5,654
	$	97,922	$	30,175	$	128,097
Operating segment:
RNG	$	92,268	$	21,931	$	114,199
REG		5,654		8,244		13,898
	$	97,922	$	30,175	$	128,097

Practical expedients and remaining performance obligations

The Company recognizes the sale of natural gas and electric commodities using the right to invoice practical expedient. The Company determined that the revenues recognized as of period end correspond directly with the value transferred to customers and the Company's satisfaction of the performance obligations to date. Furthermore, with the application of the right to invoice practical expedient and in consideration that contracts related to future environmental attributes sales do not exceed one year, there were no remaining unsatisfied or partially satisfied performance obligations as of September 30, 2024 and December 31, 2023, respectively.

NOTE 5 – ACCOUNTS AND OTHER RECEIVABLES

The Company extends credit based upon an evaluation of the customer’s financial condition and, while collateral is not required, the Company periodically receives surety bonds that guarantee payment. Credit terms are consistent with industry standards and practices. Reserves for uncollectible accounts, if any, are recorded as part of general and administrative expenses in the consolidated statements of operations. No reserve expense was recorded for the three and nine months ended September 30, 2024 and 2023.

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Accounts and other receivables consist of the following as of September 30, 2024 and December 31, 2023:


	September 30, 2024		December 31, 2023
Accounts receivables	$	19,056	$	12,557
Other receivables		145		148
Reimbursable expenses		16		47
Accounts and other receivables, net	$	19,217	$	12,752

NOTE 6 – PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant and equipment consists of the following as of September 30, 2024 and December 31, 2023:


	September 30, 2024			December 31, 2023
Land	$	1,568		$	748
Buildings and improvements		36,506			30,329
Machinery and equipment		276,078			255,421
Gas mineral rights		35,526			35,526
Construction work in progress		90,122			67,747
Total	$	439,800		$	389,771
Less: Accumulated depreciation and amortization		(189,955	)		(175,482	)
Property, plant & equipment, net	$	249,845		$	214,289

Depreciation expense for property plant and equipment was $5,691 and $4,956 for the three months ended September 30, 2024 and 2023, respectively, and $16,245 and $14,624 for the nine months ended September 30, 2024 and 2023, respectively. Depletion expense for gas mineral rights was $91 and $129 for the three months ended September 30, 2024 and 2023, respectively, and $273 and $385 for the nine months ended September 30, 2024 and 2023, respectively.

Construction work in progress consists of RNG and REG capital expenditures on developmental projects and improvements to existing sites. Projects, on average, last between 18 to 36 months, and when completed for their intended use, costs are placed in service and begin depreciating.

In February 2024, the Company completed an Asset acquisition with a privately-held entity. The Company paid $820 for land located in North Carolina. The Asset acquisition was accounted for as an asset purchase in accordance with ASC 805, Business Combinations, and the purchase price has been allocated all to land within Property, plant and equipment, net on the Company's consolidated balance sheet.

NOTE 7 – GOODWILL AND INTANGIBLE ASSETS, NET

Goodwill and intangible assets consist of the following as of September 30, 2024 and December 31, 2023:


	September 30, 2024		December 31, 2023
Goodwill	$	60	$	60
Intangible assets with indefinite lives:
Land use rights		328		329
Total intangible assets with indefinite lives:	$	328	$	329
Intangible assets with finite lives:
Interconnection, net of accumulated amortization of $4,406 and $3,847	$	14,803	$	14,584
Customer contracts, net of accumulated amortization of $17,415 and $17,254		3,269		3,448
Total intangible assets with finite lives:	$	18,072	$	18,032
Total Goodwill and Intangible assets	$	18,460	$	18,421

As of September 30, 2024, the weighted average remaining useful lives for customer contracts and interconnections were 13 and 14 years, respectively. Amortization expense was $248 and $243 for the three months ended September 30, 2024 and 2023, respectively and $738 and $729 for the nine months ended September 30, 2024 and 2023, respectively.

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NOTE 8 – ASSET RETIREMENT OBLIGATIONS

The Company accounts for asset retirement obligations by recording the fair value of the liability in the period in which it is incurred. The Company estimates the fair value of asset retirement obligations by calculating the estimated present value of the cost to retire the asset. Factors that are considered when determining the present value of the cost to retire the asset include future inflation and discount rates, along with estimates date(s) of retiring the asset. Additionally, changes in legal, regulatory, environmental, and political environments can affect the fair value of the obligations. As such, asset retirement obligations are considered a Level 3 financial instrument.

The $218 change in estimates for the nine months ended September 30, 2024 was due to RNG fuel supply agreement extensions and an RNG project that necessitated reassessments. The $225 reduction in the liability was due to an REG site sale as described in Note 3.

The following table summarizes the activity associated with asset retirement obligations of the Company as of September 30, 2024 and December 31, 2023:


	Nine months ended September 30,			Year ended December 31,
	2024			2023
Asset retirement obligations—beginning of period	$	5,900		$	5,493
Accretion expense		333			407
Changes in estimate		218		—
Liabilities associated with properties sold		(225	)	—
Asset retirement obligations—end of period	$	6,226		$	5,900

NOTE 9 – DERIVATIVE INSTRUMENTS

To mitigate market risk associated with fluctuations in interest rates, the Company utilizes swap contracts under a board-approved program. The Company does not apply hedge accounting to any of its derivative instruments, and all realized and unrealized gains and losses from changes in derivative values are recognized in earnings each period. As a result of the economic hedging strategies employed, the Company had the following cash gains/losses and non-cash gains/losses in the consolidated statements of operations for the three and nine months ended September 30, 2024 and 2023:


		For the three months ended September 30,
Derivative Instrument	Location	2024			2023
Interest rate swaps	Interest expense	$	(674	)	$	41
Net (loss) gain		$	(674	)	$	41

		For the nine months ended September 30,
Derivative Instrument	Location	2024			2023
Interest rate swaps	Interest expense	$	(648	)	$	160
Net (loss) gain		$	(648	)	$	160

NOTE 10 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company’s assets and liabilities that are measured at fair value on a recurring basis include the following as of September 30, 2024 and December 31, 2023, set forth by level, within the fair value hierarchy:


	September 30, 2024
	Level 1		Level 2		Level 3			Total
Interest rate swap derivative asset	$	—	$	607	$	—		$	607
Asset retirement obligations		—		—		(6,226	)		(6,226	)
Pico earn-out liability		—		—		(3,365	)		(3,365	)
	$	—	$	607	$	(9,591	)	$	(8,984	)

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	December 31, 2023
	Level 1		Level 2		Level 3			Total
Interest rate swap derivative asset	$	—	$	1,255	$	—		$	1,255
Asset retirement obligations		—		—		(5,900	)		(5,900	)
Pico earn-out liability		—		—		(5,109	)		(5,109	)
	$	—	$	1,255	$	(11,009	)	$	(9,754	)

The three levels of the fair value hierarchy under authoritative guidance are described as follows:

Level 1: Observable inputs that reflect unadjusted quoted market prices in active markets for identical assets or liabilities.

Level 2: Inputs are market data, other than Level 1, that are observable either directly or indirectly. Level 2 inputs include quoted market prices for similar assets or liabilities, quoted market prices for similar assets or liabilities in inactive markets and other observable information that can be corroborated by market data.

Level 3: Unobservable inputs that are not corroborated by market data, but significant to the fair value measurement.

A summary of change in the fair value of the Company’s Level 3 instrument, attributable to asset retirement obligations, for the nine months ended September 30, 2024 and the year ended December 31, 2023 is included in Note 8. The Company’s earn-out fair value liability at its Idaho agricultural digester site is determined by calculating the estimated present value of the future obligation. The present value is assessed quarterly and is based on macro-economic factors such as inflation and risk free US Treasury rates. Company specific estimates utilized include current and future interest rates, digester inlet gas flow and projected EBITDA. A weighted average probability approach is utilized for the variables discussed above. The earn-out is classified as a Level 3 financial instrument and changes in the balance are recorded in Accrued liabilities and Other liabilities within the consolidated balance sheets and in the Royalties, transportation, gathering and production fuel within the consolidated statements of operations. Interest rate swap derivatives are classified as Level 2 financial instruments and are valued utilizing quoted forward Bloomberg Short-Term Bank Yield Index Rates. In addition, certain assets are measured at fair value on a non-recurring basis when an indicator of impairment is identified and the assets’ fair values are determined to be less than its carrying value. See Note 3 for additional information.

NOTE 11 – ACCRUED LIABILITIES

The Company’s accrued liabilities consists of the following as of September 30, 2024 and December 31, 2023:


	September 30, 2024		December 31, 2023
Accrued expenses	$	5,160	$	3,983
Payroll and related benefits		2,541		2,355
Royalty		6,006		3,897
Utility		1,585		1,653
Accrued interest		329		827
Other		142		74
Accrued liabilities	$	15,763	$	12,789

NOTE 12 – DEBT

The Company’s debt consists of the following as of September 30, 2024 and December 31, 2023:


	September 30, 2024			December 31, 2023
Term loans	$	58,000		$	64,000
Less: current principal maturities		(11,000	)		(8,000	)
Less: debt issuance costs (on long-term debt)		(281	)		(386	)
Long-term debt	$	46,719		$	55,614
Current portion of long-term debt		10,868			7,886
Total debt	$	57,587		$	63,500

Amended Credit Agreement

On December 12, 2018, Montauk Energy Holdings LLC (“MEH”), a wholly owned subsidiary of the Company, entered into the Second Amended and Restated Revolving Credit and Term Loan Agreement (as amended, “Credit Agreement”), by and among MEH, the financial institutions from time to time party thereto as lenders and Comerica Bank, as the administrative agent, sole lead arranger

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and sole bookrunner (“Comerica”). The Credit Agreement (i) amended and restated in its entirety MEH’s prior revolving credit and term loan facility, dated as of August 4, 2017, as amended, with Comerica and certain other financial institutions and (ii) replaced in its entirety the prior credit agreement, dated as of August 4, 2017, as amended, between Comerica and Bowerman Power LFG, LLC, a wholly-owned subsidiary of MEH.

On March 21, 2019, MEH entered into the first amendment to the Credit Agreement (the “First Amendment”), which clarified a variety of terms, definitions and calculations in the Credit Agreement. The Credit Agreement requires the Company to maintain customary affirmative and negative covenants, including certain financial covenants, which are measured at the end of each fiscal quarter. On September 12, 2019, the Company entered into the second amendment to the Credit Agreement (the "Second Amendment"). Among other matters, the Second Amendment redefined the Fixed Charge Coverage Ratio (as defined in the Credit Agreement), reduced the commitments under the revolving credit facility to $80,000, redefined the Total Leverage Ratio (as defined in the Credit Agreement) and eliminated the RIN Floor (as defined in the Second Amendment) as an Event of Default. In connection with the Second Amendment, the Company paid down the outstanding term loan by $38,250 and the resulting quarterly principal installments were reduced to $2,500.

On January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC (a direct wholly-owned subsidiary of MNK at the time, “Montauk USA”) entered into a series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions,” that resulted in the Company owning all of the assets and entities (other than Montauk USA) previously owned by Montauk USA, and Montauk Renewables became a direct wholly-owned subsidiary of MNK. In connection with the completion of the Reorganization Transactions and the IPO, the Company entered into the third amendment to the Credit Agreement (the “Third Amendment”). This amendment permitted the change of control provisions, as defined in the underlying agreement, to permit the Reorganization Transactions and the IPO to be completed.

On December 21, 2021, MEH entered into the fourth amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement ("the Fourth Amendment"). The current credit agreement, which is secured by a lien on substantially all assets of the Company and certain of its subsidiaries, provides for a $80,000 term loan, a $120,000 revolving credit facility, and includes a $75,000 accordion feature. The term loan amortizes in quarterly installments of $2,000 through 2024, then increases to $3,000 from 2025 to 2026, with a final payment of $32,000 in late 2026.

The Company accounted for the Fourth Amendment as both a debt modification and debt extinguishment in accordance with ASC 470, Debt (“ASC 470”). In connection with the Credit Agreement, the Company paid $2,027 in fees. Of this amount, $326 was expensed and $1,701 was capitalized and will be amortized over the life of the Credit Agreement. Amortized debt issuance expense was $90 and $92 for the three months ended September 30, 2024 and 2023, respectively, and $270 and $276 for the nine months ended September 30, 2024 and 2023, respectively, and was recorded within interest expense on the Consolidated Statement of Operations.

As of September 30, 2024, $58,000 was outstanding under the term loan. In addition, the Company had $2,185 of outstanding letters of credit as of September 30, 2024. Amounts available under the revolving credit facility are reduced by any amounts outstanding under letters of credit. As of September 30, 2024, the Company’s capacity available for borrowing under the revolving credit facility was $117,815. As of September 30, 2024, borrowings of the term loans and revolving credit facility bear interest at the Bloomberg Short-Term Bank Yield Index Rate, plus an applicable margin. Interest rates as of September 30, 2024 and December 31, 2023 were 6.12% and 6.11%, respectively.

As of September 30, 2024, the Company was in compliance with all applicable financial covenants under the Credit Agreement.

NOTE 13 – INCOME TAXES

The Company’s provision for income taxes in interim periods is typically computed by applying the estimated annual effective tax rates to income or loss before income taxes for the period. In addition, non-recurring or discrete items are recorded during the period in which they occur. For the nine months ended September 30, 2024, the Company utilized an estimated effective tax rate.


	For the three months ended September 30,
	2024			2023
Expense provision for income taxes	$	3,965		$	2,808
Effective tax rate		19	%		18	%


	For the nine months ended September 30,
	2024			2023
Expense provision for income taxes	$	4,722		$	2,681
Effective tax rate		21	%		21	%

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The effective tax rate of 19% for the three months ended September 30, 2024 differed slightly from the rate for the three months ended September 30, 2023 of 18% primarily due to both periods having discrete events related to stock compensation and production tax credits.

The effective tax rate of 21% for the nine months ended September 30, 2024 was unchanged compared to the rate for the nine months ended September 30, 2023 of 21% primarily due to both periods having discrete events related to stock compensation as compared to the year to date pre-tax book income.

Income tax expense for the three and nine months ended September 30, 2024 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21% primarily due to the benefit from production tax credits and stock related discrete items.

NOTE 14 – SHARE-BASED COMPENSATION

The board of directors of Montauk Renewables adopted the Montauk Renewables, Inc. Equity and Incentive Compensation Plan (“MRI EICP”) in January 2021. Following the closing of the IPO, the board of directors of Montauk Renewables approved the grant of non-qualified stock options, restricted stock units and restricted share awards to the employees of Montauk Renewables and its subsidiaries in January 2021. In connection with the restricted share awards, the officers of the Company made elections under Section 83(b) of the Code. Pursuant to such elections, the Company withheld 950,214 shares of common stock from such awards at a price of $11.38 per share from such awards. The Company records and reports restricted shares and restricted stock units when vested and in the case of options, when such awards are settled in the Company’s common stock. Stock compensation expense related to these awards was $502 and $685 for the three months ended September 30, 2024 and September 30, 2023, respectively and $1,203 and $1,279 for the nine months ended September 30, 2024 and September 30, 2023, respectively.

In connection with a May 2021 asset acquisition, 1,250,000 restricted share awards (“RS Awards”) were granted to two employees that were hired by the Company in connection with such acquisition. The RS Awards were to vest over a five-year period and subject to the achievement of time and performance-based vesting criteria over such period. In May 2022, the RS Awards were amended to remove the performance-based vesting criteria and will only be subject to time-based vesting requirements over a five-year period. The awards were revalued at $15,500. Stock compensation expense related to these awards was $3,122 and $1,227 for the three months ended September 30, 2024 and September 30, 2023, respectively and $5,446 and $3,681 for the nine months ended September 30, 2024, and September 30, 2023 respectively. During the third quarter of 2024, the Company recognized $2,911 of non-cash stock compensation expense. This nonrecurring expense recorded within General and administration expense was related to the acceleration of previously unrecognized stock compensation expense related to an employment termination.

In 2023, the board of directors of the Company approved the grant of non-qualified stock options to the executive officers of the Company, which vest ratably over a period of three to five years. Stock compensation expense related to these awards was $657 and $588 for the three months ended September 30, 2024 and September 30, 2023, respectively and $1,972 and $1,035 for the nine months ended September 30, 2024, and September 30, 2023, respectively.

The restricted shares, restricted stock units and option awards are subject to vesting schedules and are subject to the terms and conditions of the MRI EICP and related award agreements including, in the case of the restricted share awards, each officer having made an election under Section 83(b) of the Code.

Options granted under the MRI EICP allow the recipient to receive the Company’s common stock equal to the appreciation in the fair market value of the Company’s common stock between the grant date and the exercise and settlement of options into shares as of the exercise dates. The fair value of the MRI EICP options was estimated using the Black-Scholes option pricing model. Three

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blocks of options have been awarded since inception of the plan with the following weighted-average assumptions (no dividends were expected):


	September 2023 Awards
Options awarded		225,000
Risk-free interest rate	4.44%-4.65%
Expected volatility	71%-73%
Expected option life (in years)	3.5-5.5
Grant-date fair value	$	5.72

	April 2023 Awards
Options awarded		2,100,000
Risk-free interest rate	3.71%-3.97%
Expected volatility	78%-80%
Expected option life (in years)	3.5-5.5
Grant-date fair value	$	4.25

	January 2021 Awards
Options awarded		950,214
Risk-free interest rate		0.5	%
Expected volatility		32	%
Expected option life (in years)		5.5
Grant-date fair value	$	3.44

The following table summarizes the restricted shares, restricted stock units and options outstanding under the MRI EICP as of September 30, 2024 and September 30, 2023, respectively:


	Restricted Shares					Restricted Stock Units					Options
	Number of shares			Weighted Average Grant Date Fair Value		Number of shares			Weighted Average Grant Date Fair Value		Number of shares		Weighted Average Exercise Price
End of period - December 31, 2023		1,638,678		$	11.91		150,000		$	10.09		2,325,000	$	7.04
Beginning of period - January 1, 2024		1,638,678		$	11.91		150,000		$	10.09		2,325,000	$	7.04
Granted		—			—		10,000			6.48		—		—
Vested		(911,507	)		11.95		—			—		—		—
Forfeited		—			—		—			—		—		—
End of period - Balance at September 30, 2024		727,171		$	11.85		160,000		$	9.87		2,325,000	$	7.04

End of period - December 31, 2022		2,028,301		$	11.80		280,000		$	10.13		—	$	—
Beginning of period - January 1, 2023		2,028,301		$	11.80		280,000		$	10.13		—	$	—
Granted		—		—			—			—		2,325,000		4.39
Vested		(215,165	)		11.38		—			—		—		—
Forfeited		(73,395	)		11.38		(80,000	)		10.23		—		—
End of period - September 30, 2023		1,739,741		$	11.87		200,000		$	10.09		2,325,000	$	4.39

As of September 30, 2024 no vested options have been exercised. Unrecognized MRI EICP compensation expense for awards the Company expects to vest as of September 30, 2024, was $9,600 and will be recognized over approximately 4 years.

NOTE 15 – DEFINED CONTRIBUTION PLAN

The Company maintains a 401(k) defined contribution plan for eligible employees. The Company matches 50% of an employee’s deferrals up to 4%. The Company also contributes 3% of eligible employee’s compensation expense as a safe harbor contribution. The matching contributions vest ratably over four years of service, while the safe harbor contributions vest immediately. Incurred expense related to the 401(k) plan was $168 and $166 for the three months ended September 30, 2024 and 2023, respectively, and $580 and $496 for the nine months ended September 30, 2024 and 2023, respectively.

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NOTE 16 – RELATED PARTY TRANSACTIONS

Intercompany Transactions

On January 26, 2021, the Company entered into a Loan Agreement and Secured Promissory Note (the “Initial Promissory Note”) with Montauk Holdings Limited (“MNK”). MNK is currently an affiliate of the Company and certain of the Company’s directors are also directors and executive officers of MNK. Pursuant to the Initial Promissory Note, the Company advanced a cash loan of $5,000 to MNK for MNK to pay its dividend's tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended (the “South African Income Tax Act”). On February 22, 2021, the Company and MNK entered into an Amended and Restated Promissory Note (the “Amended Promissory Note”) to increase the principal amount of the loan to a total of $7,140, in the aggregate, on December 22, 2021 entered into the Second Amended and Restated Loan Agreement and Secured Promissory Note (the “Second Amended Promissory Note”) to increase the principal amount of the loan to a total of $8,940, in the aggregate, and on December 22, 2022 entered into the First Amendment of the Second Amended and Restated Loan Agreement and Secured Promissory Note (the “First Amendment of Second Amended Promissory Note”) to amend the maturity date to June 30, 2023, and on June 21, 2023 entered into the Third Amended and Restated Loan Agreement and Secured Promissory Note (the "Third Amended and Restated Loan Agreement and Secured Promissory Note") to increase the principal amount of the loan to a total of $10,040, in the aggregate and extend the maturity date of the loan to December 31, 2023 and on December 27, 2023 entered into the Fourth Amended and Restated Loan Agreement and Secured Promissory Note to extend the maturity date of the loan to December 31, 2033, each in accordance with the Company’s obligations set forth in the transaction implementation agreement entered into by and among the Company, MNK and the other party thereto, dated November 6, 2020, and amended on January 14, 2021. The Third Amended and Restated Loan Agreement and Secured Promissory Note increased the security interest of the Company from 800,000 shares of the common stock of the Company to 976,623 shares of the Company owned by MNK. MNK is required to use the proceeds of any such sale of the shares to repay the note. The Amended Promissory Note has default provisions where MNK will deliver any unsold shares of the Company back to the Company to satisfy repayment of the note.

Under applicable guidance for variable interest entities in ASC 810, Consolidation, the Company determined that MNK is a variable interest entity. The Company concluded that it is not the primary beneficiary of the variable interest entity, as the Company does not have a controlling financial interest and does not have the power to direct the activities that most significantly impact the economic performance of MNK. Accordingly, the Company concluded that presentation of the Amended Promissory Note as a related party receivable remains appropriate. The maximum exposure to loss is limited to the Promissory Note principal and accrued interest, which totaled $10,168 and $10,138 as of September 30, 2024 and December 31, 2023, respectively.

MNK was delisted from the JSE on January 26, 2021. The MNK Board of Directors and Shareholders held its annual general meeting in March 2023 and voted to take MNK private.

Employment Transactions

The Company signed a long-term immaterial lease in December 2023 with a landowner in North Carolina. This lease enabled the Company to construct a feedstock collection system on the property which is owned by the Company. In September 2024, the Company hired the landowner as an employee to assist in the procuring of additional long-term leases on farms for additional collection system installations related to feedstock in North Carolina.

Related Party Reimbursements

Periodically the Company will reimburse MNK and HCI Managerial Services Proprietary Limited, the administrator for the Company’s secondarily listed Johannesburg Stock Exchange trading symbol, for expenses incurred on behalf of the Company. Amounts reimbursed were $4 for each of the three months ended September 30, 2024 and 2023 and $12 and $106 for the nine months ended September 30, 2024 and 2023, respectively. As of September 30, 2024 and December 31, 2023, respectively, $44 and $11 were owed.

NOTE 17 – SEGMENT INFORMATION

The Company’s operating segments for the three and nine months ended September 30, 2024 and 2023 are Renewable Natural Gas and Renewable Electricity Generation. Renewable Natural Gas includes the production of RNG. Renewable Electricity Generation includes generation of electricity at biogas-to-electricity plants. The Corporate segment is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation of the Company’s condensed consolidated financial statements. The following tables are consistent with the manner in which the chief operating decision maker evaluates the

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performance of each segment and allocates the Company’s resources. In the following tables, “RNG” refers to Renewable Natural Gas and “REG” refer to Renewable Electricity Generation.


	Three months ended September 30, 2024
	RNG		REG			Corporate			Total
Total revenue	$	61,750	$	4,167		$	—		$	65,917
Net income (loss)		33,615		(619	)		(15,948	)		17,048
EBITDA		38,320		667			(10,091	)		28,896
Adjusted EBITDA (1)		38,525		996			(10,091	)		29,430
Total assets		184,201		103,673			86,244			374,118
Capital expenditures		5,803		6,627			141			12,571

(1)

Third quarter of 2024 EBITDA Reconciliation

The following table is a reconciliation of the Company’s reportable segments’ net income (loss) from continuing operations to Adjusted EBITDA for the three months ended September 30, 2024:


	Three months ended September 30, 2024
	RNG		REG			Corporate			Total
Net income (loss)	$	33,615	$	(619	)	$	(15,948	)	$	17,048
Depreciation, depletion and amortization		4,705		1,286			57			6,048
Interest expense		—		—			1,835			1,835
Income tax expense		—		—			3,965			3,965
EBITDA	$	38,320	$	667		$	(10,091	)	$	28,896
Impairment loss		204		329			—			533
Net loss on sale of assets		1		—			—			1
Adjusted EBITDA	$	38,525	$	996		$	(10,091	)	$	29,430


	Three months ended September 30, 2023
	RNG		REG		Corporate			Total
Total revenue	$	50,935	$	4,753	$	—		$	55,688
Net income (loss)		24,159		704		(11,929	)		12,934
EBITDA		28,143		2,005		(7,765	)		22,383
Adjusted EBITDA (2)		28,194		2,005		(7,765	)		22,434
Total assets		172,888		65,048		107,675			345,611
Capital expenditures		8,673		7,105		41			15,819

(2) Third quarter of 2023 EBITDA Reconciliation

The following table is a reconciliation of the Company’s reportable segments’ net income (loss) from continuing operations to Adjusted EBITDA for the three months ended September 30, 2023:


	Three months ended September 30, 2023
	RNG		REG		Corporate			Total
Net income (loss)	$	24,159	$	704	$	(11,929	)	$	12,934
Depreciation, depletion and amortization		3,984		1,301		61			5,346
Interest expense		—		—		1,295			1,295
Income tax expense		—		—		2,808			2,808
EBITDA	$	28,143	$	2,005	$	(7,765	)	$	22,383
Impairment loss		51		—		—			51
Adjusted EBITDA	$	28,194	$	2,005	$	(7,765	)	$	22,434

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For the three months ended September 30, 2024 and 2023, two and four customers, respectively, made up greater than 10% of total revenues.


	Three months ended September 30, 2024
	RNG			REG		Corporate		Total
Customer A		29.1	%		—		—		29.1	%
Customer B		15.1	%		—		—		15.1	%


	Three months ended September 30, 2023
	RNG			REG		Corporate		Total
Customer A		21.9	%		—		—		21.9	%
Customer B		19.0	%		—		—		19.0	%
Customer C		13.8	%		—		—		13.8	%
Customer D		10.9	%		—		—		10.9	%


	Nine months ended September 30, 2024
	RNG		REG			Corporate			Total
Total revenue	$	134,575	$	13,467		$	—		$	148,042
Net income (loss)		56,866		(1,193	)		(37,487	)		18,186
EBITDA		70,176		2,635			(28,313	)		44,498
Adjusted EBITDA (3)		70,839		3,276			(28,252	)		45,863
Total assets		184,201		103,673			86,244			374,118
Capital expenditures		21,085		31,767			482			53,334

(3) First nine months of 2024 EBITDA Reconciliation

The following table is a reconciliation of the Company’s reportable segments’ net income (loss) from continuing operations to Adjusted EBITDA for the nine months ended September 30, 2024:


	Nine months ended September 30, 2024
	RNG		REG			Corporate			Total
Net income (loss)	$	56,866	$	(1,193	)	$	(37,487	)	$	18,186
Depreciation, depletion and amortization		13,310		3,827			168			17,305
Interest expense		—		1			4,284			4,285
Income tax expense		—		—			4,722			4,722
EBITDA	$	70,176	$	2,635		$	(28,313	)	$	44,498
Impairment loss		591		641			—			1,232
Net loss on sale of assets		72		—			—			72
Transaction costs		—		—			61			61
Adjusted EBITDA	$	70,839	$	3,276		$	(28,252	)	$	45,863


	Nine months ended September 30, 2023
	RNG		REG			Corporate			Total
Total revenue	$	114,328	$	13,769		$	—		$	128,097
Net income (loss)		42,847		(97	)		(32,601	)		10,149
EBITDA		54,570		3,788			(26,055	)		32,303
Adjusted EBITDA (4)		55,384		3,788			(25,969	)		33,203
Total assets		172,888		65,048			107,675			345,611
Capital expenditures		33,863		11,498			45			45,406

(4) First nine months of 2023 EBITDA Reconciliation

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The following table is a reconciliation of the Company’s reportable segments’ net income (loss) from continuing operations to Adjusted EBITDA for the nine months ended September 30, 2023:


	Nine months ended September 30, 2023
	RNG		REG			Corporate			Total
Net income (loss)	$	42,847	$	(97	)	$	(32,601	)	$	10,149
Depreciation, depletion and amortization		11,723		3,885			184			15,792
Interest expense		—		—			3,681			3,681
Income tax benefit		—		—			2,681			2,681
EBITDA	$	54,570	$	3,788		$	(26,055	)	$	32,303
Impairment loss		777		—			—			777
Net loss on sale of assets		37		—			—			37
Transaction costs		—		—			86			86
Adjusted EBITDA	$	55,384	$	3,788		$	(25,969	)	$	33,203

For both the nine months ended September 30, 2024 and 2023, four customers made up greater than 10% of total revenues.


	Nine months ended September 30, 2024
	RNG			REG		Corporate		Total
Customer A		17.5	%		—		—		17.5	%
Customer B		16.3	%		—		—		16.3	%
Customer C		16.1	%		—		—		16.1	%
Customer D		11.8	%		—		—		11.8	%


	Nine months ended September 30, 2023
	RNG			REG		Corporate		Total
Customer A		21.1	%		—		—		21.1	%
Customer B		13.0	%		—		—		13.0	%
Customer C		12.0	%		—		—		12.0	%
Customer D		10.9	%		—		—		10.9	%

NOTE 18 – LEASES

The Company leases office space and other office equipment under operating lease arrangements (with initial terms greater than twelve months), expiring in various years through 2033. These leases have been entered into to better enable the Company to conduct business operations. Office space is leased to provide adequate workspace for employees in Pittsburgh, Pennsylvania and Houston, Texas. Office space and office equipment agreements that exceed 12 months are accounted for as operating leases in accordance with ASC 842, Leases.

The Company also leases safety equipment for the various operational sites in the United States. The term of certain equipment exceeds twelve months and is accordingly classified as a finance lease under ASC 842. These finance leases expire in 2026 and were entered into in order to provide a safe work environment for operational employees.

The Company determines if an arrangement is, or contains, a lease at inception based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. For all operating and finance lease arrangements, the Company presents at the commencement date: a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.

The Company has elected, as a practical expedient, not to separate non-lease components from lease components, and instead account for each separate component as a single lease component for all lease arrangements, as lessee. In addition, the Company has elected, as a practical expedient, not to apply lease recognition requirements to leases with a term of one year or less. In determination of the lease term, the Company considers the likelihood of lease renewal options and lease termination provisions.

The Company uses its incremental borrowing rate, as the basis to calculate the present value of future lease payments at lease commencement. The incremental borrowing rate represents the rate that would approximate the rate to borrow funds on a collateralized basis over a similar term and in a similar economic environment.

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Supplemental information related to operating lease arrangements was as follows:


	For the three months ended September 30,
	2024			2023
Cash paid for amounts included in the measurement of operating lease liabilities	$	152		$	108
Weighted average remaining lease term (in years)		5.58			6.08
Weighted average discount rate		5.00	%		5.00	%


	For the nine months ended September 30,
	2024			2023
Cash paid for amounts included in the measurement of operating lease liabilities	$	484		$	280
Weighted average remaining lease term (in years)		5.58			6.08
Weighted average discount rate		5.00	%		5.00	%

Future minimum operating lease payments are as follows:


Year Ending
2024	$	152
2025		649
2026		599
2027		583
2028		594
Thereafter		2,713
Imputed interest		(984	)
Total	$	4,306

Supplemental information related to finance lease arrangements was as follows:


	For the three months ended September 30,
	2024			2023
Cash paid for amounts included in the measurement of financing lease liabilities	$	19		$	19
Weighted average remaining lease term (in years)		2.75			0.40
Weighted average discount rate		5.00	%		5.00	%


	For the nine months ended September 30,
	2024			2023
Cash paid for amounts included in the measurement of financing lease liabilities	$	51		$	57
Weighted average remaining lease term (in years)		2.75			0.40
Weighted average discount rate		5.00	%		5.00	%

Future minimum finance lease payments are as follows:


Year Ending
2024	$	19
2025		76
2026		32
2027		1
2028		1
Thereafter		10
Imputed interest		(10	)
Total	$	129

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NOTE 19 – INCOME PER SHARE

Basic and diluted income per share was computed using the following common share data for the three and nine months ended September 30, 2024 and 2023, respectively:


	For the three months ended September 30,
	2024		2023
Net income	$	17,048	$	12,934
Basic weighted-average shares outstanding		142,410,940		141,717,612
Dilutive effect of share-based awards		209,392		582,263
Diluted weighted-average shares outstanding		142,620,332		142,299,875
Basic income per share	$	0.12	$	0.09
Diluted income per share	$	0.12	$	0.09


	For the nine months ended September 30,
	2024		2023
Net income	$	18,186	$	10,149
Basic weighted-average shares outstanding		142,156,540		141,661,790
Dilutive effect of share-based awards		175,001		339,037
Diluted weighted-average shares outstanding		142,331,541		142,000,827
Basic income per share	$	0.13	$	0.07
Diluted income per share	$	0.13	$	0.07

NOTE 20 – COMMITMENTS AND CONTINGENCIES

Environmental

The Company is subject to a variety of environmental laws and regulations governing discharges to the air and water, as well as the handling, storage and disposing of hazardous or waste materials. The Company believes its operations currently comply in all material respects with all environmental laws and regulations applicable to its business. However, there can be no assurance that environmental requirements will not change in the future or that the Company will not incur significant costs to comply with such requirements.

Contingencies

The Company, from time to time, may be involved in litigation. At September 30, 2024, management does not believe there are any matters outstanding that would have a material adverse effect on the Company’s financial position or results of operations.

NOTE 21 – SUBSEQUENT EVENTS

The Company evaluated its September 30, 2024 condensed consolidated financial statements through the date the financial statements were issued. The Company is not aware of any subsequent events which would require recognition or disclosure in the consolidated financial statements, except for the matter described below.

On October 22, 2024, the Company entered into an asset purchase agreement to sell one of its renewable natural gas sites for a purchase price of $1,000. The Company entered into this agreement for this immaterial site with the site host in advance of the expiration of the gas rights agreement at this site. The sale process is contingent on the completion of various closing conditions and administrative items.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Quarterly Report on Form 10-Q. Throughout this section, dollar amounts and production volumes are expressed in thousands, except for per share amounts, MMBtu, MWh, and RIN pricing amounts and unless otherwise indicated.

In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Cautionary Note Regarding Forward-Looking Statements,” “Item 1A.–Risk Factors” of our 2023 Annual Report, and elsewhere in this report.

Overview

Montauk Renewables is a renewable energy company specializing in the recovery and processing of biogas from landfills and other non-fossil fuel sources for beneficial use as a replacement to fossil fuels. We develop, own, and operate RNG projects, using proven technologies that supply RNG into the transportation industry and use RNG to produce Renewable Electricity. We are one of the largest U.S. producers of RNG, having participated in the industry for over 30 years. We established our operating portfolio of 12 RNG and two Renewable Electricity projects through self-development, partnerships, and acquisitions that span eight states.

Biogas is produced by microbes as they break down organic matter in the absence of oxygen (during a process called anaerobic digestion). Our two current sources of commercial scale biogas are LFG or ADG. We typically secure our biogas feedstock through long-term fuel supply agreements and property lease agreements with biogas site hosts. Once we secure long-term fuel supply rights, we design, build, own, and operate facilities that convert the biogas into RNG or use the processed biogas to produce Renewable Electricity. We sell the RNG and Renewable Electricity through a variety of term length agreements. Because we are capturing waste methane and making use of a renewable source of energy, our RNG and Renewable Electricity generate valuable Environmental Attributes, which we are able to monetize under federal and state renewable initiatives.

Our current operating projects produce either RNG or Renewable Electricity by processing biogas from landfill sites or agricultural waste from livestock farms. We view agricultural waste from livestock farms as a significant opportunity for us to expand our RNG business, and we continue to evaluate other agricultural feedstock opportunities. We believe that our business model and technology are highly scalable given availability of biogas from agriculturally derived sources, which will allow us to continue to grow through prudent development and complimentary acquisitions.

Recent Developments

RINs Generated but Unsold

Our profitability is highly dependent on the market price of Environmental Attributes, including the market price for RINs. As we self-market a significant portion of our RINs, a decision not to commit to transfer available RINs during a period will impact our revenue and operating profit. The following table summarizes select historical data related to RINs generated, RINs sold, and RINs generated but unsold. As we self-market a significant portion of our RINs and as the RFS is based on annual compliance, any strategic decision to not monetize available RINs in a quarter could impact the timing of operating revenues recognized during a fiscal year. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The timing of RIN transfers can vary year over year and by period within a year and is contingent on various factors including, but not limited to: (a) the Company’s expectations on RIN index price, (b) operational needs of the Company, (c) obligated parties purchase needs, or (d) the type of customer among other matters.


Calendar Quarter	RINs Available for Sale	RINs Sold	RINs sold as % of RINs Available	RINs Available but Unsold	RINs Unsold as % of RINs Available
2023 First Quarter	11,215	2,949	26.3%	8,266	73.7%
2023 Second Quarter	20,407	17,441	85.5%	2,966	14.5%
2023 Third Quarter	14,514	13,750	94.7%	764	5.3%
2023 Fourth Quarter	10,904	10,796	99.0%	108	1.0%
2024 First Quarter	11,240	7,889	70.2%	3,351	29.8%
2024 Second Quarter	14,707	10,000	68.0%	4,707	32.0%
2024 Third Quarter	15,895	15,750	99.1%	145	0.9%

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Capital Development Summary

The following summarizes our ongoing development growth plans expected capacity contribution, anticipated commencement of operations, and capital expenditure estimate, respectively excluding the Montauk Ag Renewables Development Project:


Development Opportunity	Estimated Capacity Contribution (MMBtu/day)	Anticipated Commencement Date	Estimated Capital Expenditure
Second Apex RNG Facility	2,100	2025 second quarter	$30,000-$40,000
Blue Granite RNG Facility	900	2027	$25,000-$35,000
Bowerman RNG Facility	3,600	2027	$85,000-$95,000
European Energy Facilities	N/A	2027	$65,000-$75,000

Second Apex RNG Facility

In 2022, we announced the planned construction of a second RNG processing facility at the Apex landfill. The construction of a second facility under our existing fuel supply agreement was triggered by biogas feedstock volumes exceeding production capabilities and discussions with the landfill host waste intake forecasted projections. As the landfill host continues to increase waste intake, we believe that the additional 2,100 MMBtu per day of production capacity will allow us to process the currently forecasted increase in biogas feedstock volumes. While the landfill host continues to increase waste intake, we continue to expect there could be a period where we have excess available capacity after the second facility is commissioned. We continue to incur capital expenditures for this project and continue to expect commercial operations in the second quarter of 2025.

Blue Granite RNG Project

In 2023, we announced the planned entrance into South Carolina with the development of a new landfill gas-to-RNG facility. The planned project is expected to contribute approximately 900 MMBtu per day of production capacity upon commissioning. We continue to experience delays with our interconnection, most recently due to the utility informing us of their near-term prioritization of remediation efforts from the impacts of Hurricane Helene. We continue to review various alternatives related to interconnection opportunities as part of our considerations for offtake options with the understanding those alternatives may differ from initial development project assumptions. We expect the utility interconnection initially included in our development assumptions to accept the production from this facility but will require other upgrades for their system to accommodate our interconnection. The prioritization of recovery from Hurricane Helene will delay these utility upgrades and directly impact our interconnection schedule delaying our commissioning expectation of this facility into 2027. Our pace of capital deployment for this project has slowed due to the delay of the utility and we do not expect to incur significant capital expenditures on this project through the remainder of 2024. We expect to resume capital expenditures for this project mid 2025.

Bowerman RNG Project

In 2023, we announced a planned development of a renewable natural gas landfill project in Irvine, CA at the Frank R. Bowerman Landfill. The project is anticipated to process the large and growing volumes of biogas in excess of the existing capacity of the REG facility. We currently expect facility commissioning in 2027 and continue to expect the capital investment to range between $85,000 and $95,000. As part of the agreement to develop the RNG plant, we also agreed to work with the landfill host on the landfill's management of its wellfield and its flare facility permit requirements. The landfill has proposed corresponding changes to our agreement which could have impacts to our existing, agreed upon commissioning schedule. We continue to work with the landfill on these proposed changes to assess what, if any, impact these changes could additionally have related to receipt of required regional regulatory construction permits. The project is anticipated to have production nameplate capacity of approximately 3,600 MMBtu per day, assuming currently forecasted biogas feedstock volumes that are projected to be available from the host landfill at the time of commissioning. We continue to incur capital expenditures for this project.

Carbon Dioxide Beneficial Use Opportunity

In February 2024, we signed a contract for the delivery of 140 thousand tons per year of biogenic carbon dioxide (“CO2”) from our Texas facilities. We intend to capture, clean and liquefy CO2 at select Texas facilities, at which point it will be transported to EE North America's (“EENA”), Houston Texas-based e-methanol facility. The delivery term is expected to last at least 15 years and we continue to expect delivery to begin in 2027. During the second quarter of 2024, we completed initial site surveys related to locating the CO2 processing equipment. We have also received equipment proposals from multiple vendors all having prior experience with

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liquid CO2 capture and processing. We continue to anticipate commissioning in 2027 and we expect the capital investment to range between $65,000 and $75,000 with capital expenditure beginning in 2025 for long lead equipment and design engineering.

Montauk Ag Renewables Acquisition

In 2021, through a wholly-owned subsidiary Montauk Ag Renewables, we completed an asset purchase related to developing technology to recover residual natural resources from the waste streams of modern agriculture and to refine and recycle such waste products through proprietary and other processes in order to produce high quality renewable natural gas to generate renewable electricity, to generate North Carolina swine RECs, and to produce micronutrient organic fertilizer alternatives (the “Montauk Ag Renewables Acquisition”).

In connection with the July 2023 REC agreement with Duke Energy (“Duke”), our Board of Directors approved funding for the first phase of the North Carolina development project in September 2023. Once construction has been completed on the first phase and the facility has been fully commissioned, the project will provide sufficient capacity to satisfy the Duke REC agreement through the deployment of up to seven operational processing lines at the Turkey Creek facility. Including the original equipment acquired in the Montauk Ag Renewables Acquisition, the Turkey, NC asset acquisition, and the relocation of the Magnolia, NC site reactor to Turkey, NC, we currently expect the first phase capital investment to range between $140,000 and $160,000.

We continue to engage with regulatory agencies in North Carolina to confirm the means and methods of power generation from swine waste which will be eligible for Renewable Energy Credits under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production. In early 2024, we received notification from the North Carolina Utilities Commission that the Turkey, NC location was approved for a New Renewables Energy Facility ("NREF") designation and Certificate of Public Convenience and Necessity (“CPCN”). In the first quarter of 2024, we submitted an amendment to our NREF application, deemed complete by the public staff of the North Carolina Utilities Commission ("NCUC"). In August 2024, we received notice from the NCUC that our NREF amendment application was approved. In October 2024, we received notice from the NCUC that our application for a CPCN and registration for a NREF related to the sale of electricity to generate swine RECs was approved for public notice. We continue to work with the utility providers regarding the utility infrastructure design for the electricity interconnection. Survey and pre-construction activities for the electricity interconnection remain ongoing and in line with our commissioning schedule.

We signed a receipt interconnection agreement with Piedmont Natural Gas for the Turkey, NC location. This agreement is structured to coincide with the development timeline at the Turkey, NC location. Piedmont Natural Gas has submitted the design of the gas interconnection for regulatory approval and we expect the interconnection construction to begin in 2024 and be completed in line with our commissioning timeline. This gas interconnection is a necessary for the project to begin the registration process to obtain regulatory approvals under either the federal RFS or state LCFS programs. Completing this process will enable the Turkey, NC location to have ability to use the RNG to produce electricity or to inject into the natural gas supply.

We continue to use the pilot reactor that was relocated and previously operated prior to the 2021 Montauk Ag Renewables Acquisition. In connection with the hog space cycle times with our feedstock supply partners, the pilot reactor testing includes refining feedstock conveyance, equipment processing, product gas composition, and the composition of the solid output. We have processed tested both the biogas and micronutrient organic fertilizer alternatives. We are also continuing to staff the Turkey, NC location. We continue to plan for a rolling commissioning schedule for the remaining processing lines through the second half of 2025. We expect to begin generating revenues in 2025 and have sufficient capacity to satisfy the Duke REC agreement after final commissioning during the second half of 2025.

The feedstock supply agreements we have signed allowed us to continue to refine our expected feedstock collection process. This process involves installing equipment on the farms under agreements, collecting feedstock and processing the waste through multiple phases of solids concentration at both the farm and our Turkey, NC location. We have completed the majority of the installation of collection process equipment on two farms for which we have feedstock agreements but continue to refine our collection methods. During the fourth quarter of 2024, we continue to bring additional farms under contract to secure additional feedstock supply.

We continue to develop the opportunities with Montauk Ag Renewables and can give no assurances that our plans related to this acquisition will meet our expectations. Utility interconnection, both inbound to and outbound from our centralized Turkey, NC processing facility is dependent on factors outside of our control. Our current construction timeline and costs are subject to delays or costs increases, respectively. We continue to design and plan for the development of the Turkey, NC facility to be used for commercial production. We expect the Magnolia, NC location to be used for various feedstock processing needs. Based on our current development timeline expectations, we do not expect to commence significant revenue generating activities until 2025. We intend to contract with additional farms to secure feedstock sources for future production processes.

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Waste-stream Biogas Recovery

In October 2024, a collaboration with Emvolon was announced to transform methane emissions from waste stream biogas into high-value carbon negative fuel. Leveraging Emvolon's patented technology, the initial pilot is a small-scale demonstration of recovering and converting biogas into green methanol. We expect the pilot to take place at our Atascocita facility in Houston, Texas. The pilot is designed to provide proof of concept to eventually move to a commercial facility capable of producing up to 15 thousand gallons of green methanol per year and may eventually lead to a full-scale, commercial system capable of producing up to 2,400 gallons of methanol annually at the same or similar sites. We do not expect short term financial benefits from this demonstration nor a disruption to our operations.

Key Trends

Market Trends Affecting the Renewable Fuel Market

We believe rising demand for RNG is attributable to a variety of factors, including growing public support for renewable energy, U.S. governmental actions to increase energy independence, environmental concerns increasing demand for natural gas powered vehicles, job creation, and increasing investment in the renewable energy sector.

Key drivers for the long-term growth of RNG include the following factors:

•

Regulatory or policy initiatives, including the federal RFS program and state or national-level low-carbon fuel programs in states such as California and Oregon or Canada, that drive demand for RNG and its derivative Environmental Attributes (as further described below).

•

Efficiency, mobility and capital cost flexibility in RNG operations enable them to compete successfully in multiple markets. Our operating model is nimble, as we commonly use modular equipment; our RNG processing equipment is more efficient than its fossil-fuel counterparts.

•

Demand for compressed natural gas (“CNG”) from natural gas-fueled vehicles. The RNG we create is pipeline quality and can be used for transportation fuel when converted to CNG. CNG is commonly used by medium-duty fleets that are close to fueling stations, such as city fleets, local delivery trucks and waste haulers.

•

Regulatory requirements, market pressure and public relations challenges increase the time, cost and difficulty of permitting new fossil fuel-fired facilities.

Factors Affecting Our Future Operating Results:

Conversion of Electricity Projects to RNG Projects:

We continue to evaluate opportunities to convert our remaining facilities from Renewable Electricity to RNG production. These opportunities tend to be most attractive for any merchant electricity facilities given the favorable economics for the combined sale of RNG and RINs relative to the combined sale of market rate electricity and RECs. This strategy has been an increasingly attractive avenue for growth since 2014 when RNG from landfills became eligible for D3 RINs. However, during the conversion of a project, there is a gap in production while the electricity project is offline until it commences operation as an RNG facility, which can adversely affect us. This timing effect may adversely affect our operating results as a result of our potential conversion of Renewable Electricity projects. Upon completion of a conversion, we expect that the increase in revenue upon commencement of RNG production will more than offset the loss of revenue from Renewable Electricity production. Historically, we have taken advantage of these opportunities on a gradual basis at our merchant electricity facilities, such as Atascocita and Coastal Plains.

Acquisition and Development Pipeline

The timing and extent of our development pipeline affects our operating results due to:

•

Impact of Higher Selling, General and Administrative Expenses Prior to the Commencement of a Project’s Operation: We incur significant expenses in the development of new RNG projects. Under the Biogas Regulatory Reform Rule, effective July 1, 2024, theoretical storage of RNG for future RIN generation prior to receiving EPA registration is no longer permitted and the receipt of RINs will no longer be delayed after injecting RNG into a pipeline. We expect the elimination of theoretical storage, when combined with more timely EPA registration, to not materially impact the commencement of RIN revenue generation after pipeline injection.

•

Shifts in Revenue Composition for Projects from New Fuel Sources: As we expand into livestock farm projects, our revenue composition from Environmental Attributes will change. We believe that livestock farms offer us a

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lucrative opportunity, as the value of LCFS credits for dairy farm projects, for example, are a multiple of those realized from landfill projects due to the significantly more attractive CI score of livestock farms.

•

Incurrence of Expenses Associated with Pursuing Prospective Projects That Do Not Come to Fruition: We incur expenses to pursue prospective projects with the goal of a site host accepting our proposal or being awarded a project in a competitive bidding process. Historically, we have evaluated opportunities which we decided not to pursue further due to the prospective project not meeting our internal investment thresholds or a lack of success in a competitive bidding process. To the extent we seek to pursue a greater number of projects or bidding for projects becomes more competitive, our expenses may increase.

Regulatory, Environmental and Social Trends

Regulatory, environmental and social factors are key drivers that incentivize the development of RNG and Renewable Electricity projects and influence the economics of these projects. We are subject to the possibility of legislative and regulatory changes to certain incentives, such as RINs, RECs and GHG initiatives. On July 12, 2023, the EPA issued final rules in the Federal Register for the RFS volume requirements for 2023-2025. Final volumes for cellulosic biofuel were set at 838, 1,090 and 1,376 million D3 RINs for the three years 2023, 2024 and 2025, respectively. While new RNG projects in the US in 2024 have grown at a rate of approximately 20% over 2023, there is still a shortage of cellulosic biofuel (D3 RINs) compared to the volumes set for 2024 and 2025. While the EPA denied all small refinery exemptions in 2022, a federal appeals court rejected EPA’s denial of these small refinery exemptions in July 2024. This appeal, along with the shortfall of cellulosic biofuels (D3 RINs) are expected to impact a future EPA action possibly in 2025 to balance the market. The final rule also included significant changes to the existing RFS program, referred to as biogas regulatory reform, that will require the RNG industry to modify how all RINs are generated. New RFS participating facilities that register July 1, 2024, or after will have to meet the biogas regulatory reform provisions beginning July 1, 2024. Existing RFS participating facilities which registered prior to July 1, 2024, will have until January 1, 2025, to come into compliance with biogas regulatory reforms. For existing registrants, registration updates must be submitted by October 1, 2024. On January 1, 2025, all RFS participants must comply with biogas regulatory reform provisions. The EPA finalized a limitation that biogas from one facility has a single use under the RFS as proposed (i.e., biointermediate, RNG or CNG/LNG via biogas closed distribution system). The EPA clarified that this does not preclude non-RFS uses at same facility.

The EPA has indicated it will not meet the statutorily required deadline of November 2024 to finalize 2026 obligations under the RFS. The EPA expects to target March 2025 to propose RFS obligations for 2026.

In December 2023, CARB released the formal proposal for new LCFS rules. CARB held a public workshop for the proposed rules on April 10, 2024. In early October 2024, CARB released another set of 15-day amendments with the most notable near-term change of increasing CI reduction stringency from 5% to 9% in 2025 along with a 20% to 30% reduction by 2030. The proposed rule also creates a 2045 target of 90% reduction. This reduction would have the potential impact of reducing the number of net credits in the program. A public hearing for the proposed rule is set for November 8, 2024. Final rules are expected to be submitted to CARB’s board for approval sometime in the first quarter of 2025. The industry may see pricing volatility including potential increase to LCFS credit prices. However, price increases are not anticipated until after 2025. Also in the proposed rules is a phase-out of avoided methane crediting for dairy and swine manure pathways by 2040 for CNG usage and through 2045 for RNG used to produce hydrogen. RNG projects with avoided methane that were certified before the effective date of the new regulation will be allowed three consecutive 10-year crediting periods. Avoided methane RNG projects that break ground on or after the effective date of the regulation and before January 1, 2030, will be allowed up to two consecutive 10-year crediting periods. If the executive officer of CARB approves a gas map by July 1, 2026, then physical flow of gas to California must be demonstrated by December 31, 2037. If no gas map is approved, the proposed rules will allow reporting entities until January 1, 2041 to demonstrate gas flow.

The LCFS program require annual verification of the CI score assigned to a project. Annual verification could significantly affect the profitability of a project, particularly in the case of a livestock farm project.

Factors Affecting Revenue

Our total operating revenues include renewable energy and related sales of Environmental Attributes. Renewable energy sales primarily consist of the sale of biogas, including LFG and ADG, which is either sold or converted to Renewable Electricity. Environmental Attributes are generated and monetized from the renewable energy.

We report revenues from two operating segments: Renewable Natural Gas and Renewable Electricity Generation. Corporate relates to additional discrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering, and other operations functions not otherwise allocated to a segment. As such, the Corporate segment is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.

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•

Renewable Natural Gas Revenues: We record revenues from the production and sale of RNG and the generation and sale of the Environmental Attributes derived from RNG, such as RINs and LCFS credits. Our RNG revenues from Environmental Attributes are recorded net of a portion of Environmental Attributes shared with off-take counterparties as consideration for such counterparties using the RNG as a transportation fuel. We have certain pathway provider sharing arrangements expiring at the end of 2024. While we have not experienced a significant increase in Environmental Attributes shared with pathway providers related to our current renewals in 2024, our current pathway renewals have been at higher percentages than our historical counterparty share percentages. We are seeing current proposed pathway renewals for percentages significantly higher than our historical arrangements. Historically, we have monetized less than 25% of our RNG volumes under these fixed-price agreements. The Company is considering its entry into multiple short term contracts throughout 2025, some potentially increasing its historical percentage of volumes monetized under fixed-price arrangements, to provide time for mitigation of these recent market trends.

•

Renewable Electricity Generation Revenues: We record revenues from the production and sale of Renewable Electricity and the generation and sale of the Environmental Attributes, such as RECs, derived from Renewable Electricity. All of our Renewable Electricity production is monetized under fixed-price PPAs from our existing operating projects.

•

Corporate Revenues: Corporate reports realized and unrealized gains or losses under our gas hedge programs. The Company does not have any active gas hedge programs. Corporate also relates to additional discrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment.

Our operating revenues are priced based on published index prices which can be influenced by factors outside our control, such as market impacts on commodity pricing and regulatory developments. With our royalty payments structured as a percentage of revenue, royalty payments fluctuate with changes in revenues. Due to these factors, we place a primary focus on managing production volumes and operating and maintenance expenses as these factors are more controllable by us.

RNG Production

Our RNG production levels are subject to fluctuations based on numerous factors, including:

Disruptions to Production: Disruptions to waste placement operations at our active landfill sites, severe weather events, or failure or degradation of our or a landfill operator’s equipment or interconnection or transmission problems could result in a reduction of our RNG production. We strive to proactively address any issues that may arise through preventative maintenance, process improvement and flexible redeployment of equipment to maximize production and useful life.

•

In the third quarter of 2024, we began to experience trends with several of our landfill hosts delaying its installation of or delaying our ability to install wellfield collection infrastructure in active waste placement areas, a practice historically common and critical to our projections of feedstock gas and, therefore, production. These landfill-driven delays will impact the timing of collection system enhancement installations and the resulting timing of our production increases. We expect these trends to continue through 2025.

•

Despite collaboration with the landfill host at our Rumpke facility on our gas collection efforts, wellfield extraction environmental factors continue to impact gas extraction at the site. While the landfill continues to expand its waste intake and we continue to expand wellfield collection, our volumes have been impacted during 2024. Mitigation efforts related to wellfield environmental factors will continue in in 2025 as the benefits from 2024 efforts have not currently achieve anticipated results.

•

Similar wellfield extraction environmental factors have begun to impact gas extraction at our Apex site. We have initiated collaboration efforts with the landfill to mitigate these impacts but we expect these mitigation efforts to continue in 2025.

•

The landfill host changes to their wellfield collection system at our McCarty facility has contributed to elevated nitrogen in the feedstock received by our facility. Additionally, the landfill host modified the wellfield bifurcation approach which has impacted the quantity of feedstock received at our facility. We are working with the landfill host but continue to have lower volumes of feedstock available to be processed at the McCarty facility.

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•

Quality of Biogas: We are reliant upon the quality and availability of biogas from our site partners. The quality of the waste at our landfill project sites is subject to change based on the volume and type of waste accepted. Variations in the quality of the biogas could affect our RNG production levels. At three of our projects, we operate the wellfield collection system, which allows greater control over the quality and consistency of the collected biogas. At two of our projects, McCarty and Galveston, we have operating and management agreements by which we earn revenue for managing the wellfield collection systems. Additionally, our dairy farm project benefits from the consistency of feedstock and controlled environment of collection of waste to improve biogas quality.

•

RNG Production from Our Growth Projects: We anticipate increased production at certain of our existing projects as open landfills continue to take in additional waste and the amount of gas available for collection increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project, such as those we are currently experiencing at Blue Granite as described above, would delay any realization of production from that project.

Pricing

Our Renewable Natural Gas and Renewable Electricity Generation segments’ revenues are primarily driven by the prices under our off-take agreements and PPAs and the amount of RNG and Renewable Electricity that we produce. We sell the RNG produced from our projects under a variety of termed agreements to counterparties, with contract terms varying from three years to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. All of the Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price arrangement with escalators.

The pricing of Environmental Attributes, which accounts for a substantial portion of our revenues, is subject to volatility based on a variety of factors, including regulatory and administrative actions and commodity pricing.

The sale of RINs, which is subject to market price fluctuations, accounts for a substantial portion of our revenues. We manage against the risk of these fluctuations through forward sales of RINs, with heavy emphasis on direct sales to obligated parties. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

Factors Affecting Operating Expenses

Our operating expenses include royalties, transportation, gathering and production fuel expenses, project operating and maintenance expenses, general and administrative expenses, depreciation and amortization, net loss (gain) on sale of assets, impairment loss and transaction costs. Our operating expenses can be subject to inflationary cost increases that are largely out of our control.

•

Project Operating and Maintenance Expenses: Operating and maintenance expenses primarily consist of expenses related to the collection and processing of biogas, including biogas collection system operating and maintenance expenses, biogas processing, operating and maintenance expenses, and related labor and overhead expenses. At the project level, this includes all labor and benefit costs, ongoing corrective and proactive maintenance, project level utility charges, rent, health and safety, employee communication, and other general project level expenses. Unanticipated feedstock processing or gas conditioning equipment failures occurring outside our planned preventative maintenance program can increase project operating and maintenance expenses and reduce production volumes. The timing of gas conditioning and process equipment preventative maintenance intervals could impact the timing and amount of our operating and maintenance expenses within a given quarter.

•

Royalties, Transportation, Gathering and Production Fuel Expenses: Royalties represent payments made to our facility hosts, typically structured as a percentage of revenue. Transportation and gathering expenses include capacity and metering expenses representing the costs of delivering our RNG and Renewable Electricity production to our customers. These expenses include payments to pipeline operators and other agencies that allow for the transmission of our gas and electricity commodities to end users. Production fuel expenses generally represent alternative royalty payments based on quantity usage of biogas feedstock.

•

General and Administrative Expenses: General and administrative expenses primarily consist of corporate expenses and unallocated support functions for our operating facilities, including personnel costs for executive, finance, accounting, investor relations, legal, human resources, operations, engineering, environmental registration and reporting, health and safety, IT and other administrative personnel and professional fees and general corporate expenses. From time to time, we may be parties to legal proceedings arising in the normal

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course of business which could increase our legal expenses. We expect increased general and administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2024. In August 2024, we accelerated the vesting of certain restricted share awards to a non-executive which were unvested as of June 30, 2024 as a result of the termination of the employee. We recognized $2,911 of non-cash stock compensation expense within general and administration expenses which will not be recurring. We account for share-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. For more information, see Note 14 to our unaudited condensed consolidated financial statements related to share-based compensation.

•

Depreciation and Amortization: Expenses related to the recognition of the useful lives of our intangible and fixed assets. We spend significant capital to build and own our facilities. In addition to development capital, we annually reinvest to maintain these facilities.

•

Impairment Loss: Expenses related to reductions in the carrying value(s) of fixed and/or intangible assets based on periodic evaluations whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

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Transaction Costs: Transaction costs primarily consist of expenses incurred for due diligence and other activities related to potential acquisitions and other strategic transactions.

Key Operating Metrics

Total operating revenues reflect both sales of renewable energy and sales of related Environmental Attributes. As a result, our revenues are primarily affected by unit production of RNG and Renewable Electricity, production of Environmental Attributes, and the prices at which we monetize such production. Set forth below is an overview of these key metrics:

•

Production volumes: We review performance by site based on unit of production calculations for RNG and Renewable Electricity, measured in terms of MMBtu and MWh, respectively. While unit of production measurements can be influenced by facility maintenance schedules, the metric is used to measure the efficiency of operations and the impact of optimization improvement initiatives. We monetize a majority of our RNG commodity production under variable-price agreements, based on indices. A portion of our Renewable Natural Gas segment commodity production is monetized under fixed-priced contracts. Our Renewable Electricity Generation segment commodity production is primarily monetized under fixed-priced PPAs.

•

Production of Environmental Attributes: We monetize Environmental Attributes derived from our production of RNG and Renewable Electricity. We carry-over a portion of the RINs generated from RNG production to the following year and monetize the carried over RINs in such following calendar year. A majority of our Renewable Natural Gas segment Environmental Attributes are self-monetized. A majority of our Renewable Electricity Generation segment Environmental Attributes are monetized as a component of our fixed-price PPAs.

•

Average realized price per unit of production: Our profitability is highly dependent on the commodity prices for natural gas and electricity, and the Environmental Attribute prices for RINs, LCFS credits, and RECs. Realized prices for Environmental Attributes monetized in a year may not correspond directly with that year’s production as attributes may be carried over and subsequently monetized. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

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Comparison of Three Months Ended September 30, 2024 and 2023

The following table summarizes the key operating metrics described above, which are metrics we use to measure performance.


	For the three months ended September 30,									Change
	2024			2023			Change			%
(in thousands, unless otherwise indicated)
Revenues
Renewable Natural Gas Total Revenues	$	61,750		$	50,935		$	10,815			21.2	%
Renewable Electricity Generation Total Revenues	$	4,167		$	4,753		$	(586	)		(12.3	%)

RNG Metrics
CY RNG production volumes (MMBtu)		1,392			1,380			12			0.9	%
Less: Current period RNG volumes under fixed/floor- price contracts		(389	)		(327	)		(62	)		19.0	%
Plus: Prior period RNG volumes dispensed in current period		360			367			(7	)		(1.9	%)
Less: Current period RNG production volumes not dispensed		(308	)		(320	)		12			(3.8	%)
Total RNG volumes available for RIN generation (1)		1,055			1,100			(45	)		(4.1	%)

RIN Metrics
Current RIN generation ( x 11.727) (2)		12,374			12,898			(524	)		(4.1	%)
Less: Counterparty share (RINs)		(1,185	)		(1,351	)		166			(12.3	%)
Plus: Prior period RINs carried into current period		4,707			2,967			1,740			58.6	%
Less: CY RINs carried into next CY		—			—			—			0.0	%
Total RINs available for sale (3)		15,896			14,514			1,382			9.5	%
Less: RINs sold		(15,750	)		(13,750	)		(2,000	)		14.5	%
RIN Inventory		146			764			(618	)		(80.9	%)
RNG Inventory (volumes not dispensed for RINs) (4)		308			320			(12	)		(3.8	%)
Average Realized RIN price	$	3.34		$	3.05		$	0.29			9.5	%

Operating Expenses
Renewable Natural Gas Operating Expenses	$	23,226		$	22,837		$	389			1.7	%
Operating Expenses per MMBtu (actual)	$	16.69		$	16.55		$	0.14			0.8	%

REG Operating Expenses	$	3,170		$	2,753		$	417			15.1	%
$/MWh (actual)	$	77.32		$	57.35		$	19.97			34.8	%

Other Metrics
Renewable Electricity Generation Volumes Produced (MWh)		41			48			(7	)		(14.6	%)
Average Realized Price $/MWh (actual)	$	101.63		$	99.02		$	2.61			2.6	%

(1)

RINs are generated in the month that the gas is dispensed to generate RINs, which occurs the month after the gas is produced. Volumes under fixed/floor-price arrangements generate RINs which we do not self-market.

(2)

One MMBtu of RNG has the same energy content as 11.727 gallons of ethanol, and thus may generate 11.727 RINs under the RFS program.

(3)

Represents RINs available to be self-marketed by us during the reporting period.

(4)

Represents gas production which has not been dispensed to generate RINs.

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The following table summarizes our revenues, expenses and net income for the periods set forth below:


	For the three months ended September 30,							Change
	2024		2023		Change			%
Total operating revenues	$	65,917	$	55,688	$	10,229			18.4	%
Operating expenses:
Operating and maintenance expenses		15,484		14,212		1,272			9.0	%
General and administrative expenses		10,037		7,848		2,189			27.9	%
Royalties, transportation, gathering and production fuel		11,107		11,450		(343	)		(3.0	)%
Depreciation, depletion and amortization		6,048		5,346		702			13.1	%
Impairment loss		533		51		482			945.1	%
Total operating expenses		43,209		38,907		4,302			11.1	%
Operating income	$	22,708	$	16,781	$	5,927			35.3	%
Other expenses:		1,695		1,039		656			63.1	%
Net income before income taxes:		21,013		15,742		5,271			33.5	%
Income tax expense		3,965		2,808		1,157			41.2	%
Net income	$	17,048	$	12,934	$	4,114			31.8	%

Revenues for the Three Months Ended September 30, 2024 and 2023

Total revenues in the third quarter of 2024 were $65,917 an increase of $10,229 (18.4%) compared to $55,688 in the third quarter of 2023. The increase was primarily related to an increase in the number of RINs we self-marketed from 2024 RNG production in the third quarter of 2024 compared to the third quarter of 2023. In addition, realized RIN pricing increased approximately 9.5% during the third quarter of 2024 compared to the third quarter of 2023.

Renewable Natural Gas Revenues

We produced 1,392 MMBtu of RNG during the third quarter of 2024, an increase of 12 MMBtu (0.9%) compared to 1,380 MMBtu produced in the third quarter of 2023. Our Pico facility produced 27 MMBtu more in the third quarter of 2024 compared to the third quarter of 2023 as a result of commissioning our dairy digestion expansion project. Our Raeger facility produced 15 MMBtu more in the third quarter of 2024 compared to the third quarter of 2023 as a result of plant processing equipment improvements and increased inlet flows. Our Galveston and Coastal facilities produced 27 more MMBtu in the third quarter of 2024 compared to the third quarter of 2023 due to previously disclosed third quarter of 2023 dry weather conditions impacting gas feedstock availability. Our Rumpke facility produced 59 fewer MMBtu in the third quarter of 2024 compared to the third quarter of 2023 as a result of reduced feedstock inlet due to ongoing wellfield extraction environmental factors. Our Atascocita facility produced 22 fewer MMBtu in the third quarter of 2024 compared to the third quarter of 2023 as a result of weather driven utility outages which impacted our production.

Revenues from the Renewable Natural Gas segment in the third quarter of 2024 were $61,750, an increase of $10,815 (21.2%) compared to $50,935 in the third quarter of 2023. Average commodity pricing for natural gas for the third quarter of 2024 was $2.16 per MMBtu, 15.3% lower than the third quarter of 2023. During the third quarter of 2024, we self-monetized 15,750 RINs, representing a 2,000 increase (14.5%) compared to 13,750 in the third quarter of 2023. Average pricing realized on RIN sales during the third quarter of 2024 was $3.34 as compared to $3.05 in the third quarter of 2023, an increase of 9.5%. This compares to the average D3 RIN index price for the third quarter of 2024 of $3.36 as compared to $3.01 in the third quarter of 2023, an increase of approximately 11.6%. At September 30, 2024, we had approximately 308 MMBtu available for RIN generation and we had approximately 146 RINs generated and unsold. At September 30, 2023, we had approximately 320 MMBtu available for RIN generation and 764 RINs generated and unsold.

Renewable Electricity Generation Revenues

We produced approximately 41 MWh in Renewable Electricity in the third quarter of 2024, a decrease of 7 MWh (14.6%) from 48 MWh in the third quarter of 2023. Our Security facility produced approximately 5 MWh less in the third quarter of 2024 compared to the third quarter of 2023 as a result us ceasing operations in connection with the first quarter of 2024 sale of the gas rights back to the landfill host.

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Revenues from Renewable Electricity facilities in the third quarter of 2024 were $4,167, a decrease of $586 (12.3%) compared to $4,753 in the third quarter of 2023. The decrease was primarily driven by the cessation of operations at our Security facility.

In the third quarter of 2024, 100.0% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with underlying PPAs, as compared to 100.0% in the third quarter of 2023. This provides us with certainty of price resulting from our Renewable Electricity sites.

Expenses for the Three Months Ended September 30, 2024 and 2023

General and Administrative Expenses

Total general and administrative expenses in the third quarter of 2024 were $10,037, an increase of $2,189 (27.9%) compared to $7,848 for the third quarter of 2023. Employee related costs, including stock-based compensation costs were $7,216 in the third quarter of 2024, an increase of $2,695 (59.6%) compared to $4,521 in the third quarter of 2023. The increase was primarily related to the accelerated vesting of certain restricted share awards as a result of the termination of an employee. Our corporate insurance fees decreased approximately $262 (17.1%) in the third quarter of 2024 compared to the third quarter of 2023.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in the third quarter of 2024 were $12,586, an increase of $667 (5.6%) as compared to $11,919 in the third quarter of 2023. Our McCarty facility operating and maintenance expenses increased approximately $444 primarily related to the wellfield operational enhancements. Our Atascocita facility operating and maintenance expenses increased approximately $434 primarily related to an increase in utility expense and a property tax refund received in the third quarter of 2023. Our Pico facility operating and maintenance expenses increased approximately $197 as a result of timing of digester preventative maintenance. Our Apex facility operating and maintenance expenses decreased approximately $338 primarily related to the reduced utility expense and waste disposal costs. Our Coastal facility operating and maintenance expenses decreased approximately $197 primarily related to reduced utility expense and wellfield operational enhancements.

Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the third quarter of 2024 were $10,640, a decrease of $277 (2.5%) compared to $10,917 in the third quarter of 2023. We recorded a decrease to our Pico facility earnout of approximately 27.5% during the third quarter of 2024. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 17.2% for the third quarter of 2024 from 21.4% in the third quarter of 2023.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in the third quarter of 2024 were $2,703, an increase of $483 (21.8%) compared to $2,220 in the third quarter of 2023. Our Magnolia facility operating and maintenance expenses increased approximately $458 as a result of non-capitalizable costs.

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the third quarter of 2024 were $467, a decrease of $66 (12.4%) compared to $533 in the third quarter of 2023. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses remained unchanged at 11.2%.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in the third quarter of 2024 were $11,107, a decrease of $343 (3.0%) compared to $11,450 in the third quarter of 2023. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.

Depreciation

Depreciation and amortization in the third quarter of 2024 was $6,048, an increase of $702 (13.1%) compared to $5,346 in the third quarter of 2023. The increase was associated with timing of capital investment placed into service primarily driven by our Pico Digestion Capacity Increase project.

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Impairment loss

We calculated and recorded impairment losses of $533 in the third quarter of 2024, an increase of $482 (945.1%) compared to $51 in the third quarter of 2023. The specifically identified impairments were for various RNG equipment that was deemed obsolete or inoperable for current operations and REG assets that were impacted under initial startup testing for one of our REG construction work-in-progress sites. The third quarter of 2023 impairment related to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and recorded in our RNG segment. None of the impairments were related to expected future cash flows.

Other Expenses

Other expenses in the third quarter of 2024 was $1,695, an increase of $656 (63.1%) compared to $1,039 in the third quarter of 2023. The increase was primarily related to an increase in interest expense of $540 from the third quarter of 2024 compared to the third quarter of 2023.

Income Tax Expense

Income tax expense for the three months ended September 30, 2024 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily related to vesting of restricted stock grants on stock compensation and the benefit from production tax credits.

The effective tax rate of 18.9% for the three months ended September 30, 2024 was higher than the rate for the three months ended September 30, 2023 of 17.8% primarily related to vesting of restricted stock grants on stock compensation and the benefit from production tax credits.

Operating Income (Loss) for the Three Months Ended September 30, 2024 and 2023

Operating income in the third quarter of 2024 was $22,708, an increase of $5,927 (35.3%) compared to $16,781 in the third quarter of 2023. RNG operating income for the third quarter of 2024 was $33,616, an increase of $9,553 (39.7%) compared to $24,063 in the third quarter of 2023. Renewable Electricity Generation operating loss for the third quarter of 2024 was $618, a decrease of $1,318 (188.3%) compared to operating income of $700 for the third quarter of 2023.

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Comparison of Nine Months Ended September 30, 2024 and 2023

The following table summarizes the key operating metrics described above, which are metrics we use to measure performance.


	For the nine months ended September 30,									Change
	2024			2023			Change			%
(in thousands, unless otherwise indicated)
Revenues
Renewable Natural Gas Total Revenues	$	134,575		$	114,328		$	20,247			17.7	%
Renewable Electricity Generation Total Revenues	$	13,467		$	13,769		$	(302	)		(2.2	%)

RNG Metrics
CY RNG production volumes (MMBtu)		4,188			4,163			25			0.6	%
Less: Current period RNG volumes under fixed/floor-price contracts		(1,049	)		(957	)		(92	)		9.6	%
Plus: Prior period RNG volumes dispensed in current period		358			368			(10	)		(2.7	%)
Less: Current period RNG production volumes not dispensed		(308	)		(320	)		12			(3.8	%)
Total RNG volumes available for RIN generation (1)		3,189			3,254			(65	)		(2.0	%)

RIN Metrics
Current RIN generation ( x 11.727) (2)		37,403			38,167			(764	)		(2.0	%)
Less: Counterparty share (RINs)		(3,726	)		(4,002	)		276			(6.9	%)
Plus: Prior period RINs carried into current period		108			739			(631	)		(85.4	%)
Less: CY RINs carried into next CY		—			—			—			—
Total RINs available for sale (3)		33,785			34,904			(1,119	)		(3.2	%)
Less: RINs sold		(33,639	)		(34,140	)		501			(1.5	%)
RIN Inventory		146			764			(618	)		(80.9	%)
RNG Inventory (volumes not dispensed for RINs) (4)		308			320			(12	)		(3.8	%)
Average Realized RIN price	$	3.25		$	2.59		$	0.66			25.5	%

Operating Expenses
Renewable Natural Gas Operating Expenses	$	63,835		$	59,057		$	4,778			8.1	%
Operating Expenses per MMBtu (actual)	$	15.24		$	14.19		$	1.05			7.4	%

REG Operating Expenses	$	11,208		$	10,008		$	1,200			12.0	%
$/MWh (actual)	$	80.06		$	69.99		$	10.07			14.4	%

Other Metrics
Renewable Electricity Generation Volumes Produced (MWh)		140			143			(3	)		(2.1	%)
Average Realized Price $/MWh (actual)	$	96.19		$	96.29		$	(0.10	)		(0.1	%)

(1) RINs are generated the month following the month gas is produced and dispensed. Volumes under fixed/floor arrangements generate RINs which we not self-market.
(2) One MMBtu of RNG has the same energy content as 11.727 gallons of ethanol, and thus may generate 11.727 RINs under RFS program.
(3) Represents RINs available to be self-marketed by us during the reporting period.
(4) Represents gas production on which RINs are not generated.

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The following table summarizes our revenues, expenses and net income for the periods set forth below:


	For the nine months ended September 30,							Change
	2024		2023		Change			%
Total operating revenues	$	148,042	$	128,097	$	19,945			15.6	%
Operating expenses:
Operating and maintenance expenses		48,596		43,614		4,982			11.4	%
General and administrative expenses		28,202		26,069		2,133			8.2	%
Royalties, transportation, gathering and production fuel		26,702		25,588		1,114			4.4	%
Depreciation, depletion and amortization		17,305		15,792		1,513			9.6	%
Impairment loss		1,232		777		455			58.6	%
Transaction costs		61		86		(25	)		(29.1	)%
Total operating expenses		122,098		111,926		10,172			9.1	%
Operating income	$	25,944	$	16,171	$	9,773			60.4	%
Other expenses:		3,036		3,341		(305	)		(9.1	)%
Net income before income taxes:		22,908		12,830		10,078			78.6	%
Income tax expense		4,722		2,681		2,041			76.1	%
Net income	$	18,186	$	10,149	$	8,037			79.2	%

Revenues for the Nine Months Ended September 30, 2024 and 2023

Total revenues in the first nine months of 2024 were $148,042, an increase of $19,945 (15.6%) compared to $128,097 in the first nine months of 2023. The increase was primarily related to an increase in Realized RIN pricing of approximately 25.5% during the first nine months of 2024 compared to the first nine months of 2023.

Renewable Natural Gas Revenues

We produced 4,188 MMBtu of RNG during the first nine months of 2024, an increase of 25 MMBtu (0.6%) over the 4,163 MMBtu produced in the first nine months of 2023. Our Pico facility produced 49 MMBtu more in the first nine months of 2024 compared to the first nine months of 2023 as a result of commissioning our dairy digestion expansion project. Our Coastal facility produced 95 MMBtu more in the first nine months of 2024 compared to the first nine months 2023 as a result of plant processing equipment improvements completed in 2023 and continued wellfield operational enhancements. Certain of our Houston, TX based operating sites were impacted by severe weather events during the first nine month of 2024 including multiple day extended outages from Hurricane Beryl in July 2024. We estimate that the impact from these specific storm events contributed to our volumes being reduced by approximately 100 MMBtu during the 2024 period.

Revenues from the Renewable Natural Gas segment in the first nine months of 2024 were $134,575, an increase of $20,247 (17.7%) compared to $114,328 in the first nine months of 2023. Average commodity pricing for natural gas for the first nine months of 2024 was $2.10 per MMBtu, 21.9% lower than the first nine months of 2023. During the first nine months of 2024, we self-monetized 33,639 RINs, representing a 501 decrease (1.5%) compared to 34,140 in the first nine months of 2023. Average pricing realized on RIN sales during the first nine months of 2024 was $3.25 as compared to $2.59 in the first nine months of 2023, an increase of 25.5%. This compares to the average D3 RIN index price for the first nine months of 2024 of $3.22 as compared to $2.40 in the first nine months of 2023, an increase of approximately 34.3%. At September 30, 2024, we had approximately 308 MMBtu available for RIN generation and we had approximately 146 RINs generated and unsold. At September 30, 2023, we had approximately 320 MMBtu available for RIN generation and 764 RINs generated and unsold.

Renewable Electricity Generation Revenues

We produced approximately 140 MWh in Renewable Electricity in the first nine months of 2024, a decrease of 3 MWh (2.1%) from 143 MWh in the first nine months of 2023. Our Tulsa facility produced approximately 2 MWh more in the first nine months of 2024 compared to the first nine months of 2023 as a result of engine component failures that occurred in the first nine months of 2023. Our Security facility produced approximately 5 MWh less in the first nine months of 2024 compared to the first nine months of 2023 as a result us ceasing operations in connection with the first quarter of 2024 sale of the gas rights back to the landfill host.

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Revenues from Renewable Electricity facilities in the first nine months of 2024 were $13,467, a decrease of $302 (2.2%) compared to $13,769 in the first nine months of 2023. The decrease was primarily driven by the decrease in our Security facility production volumes.

In the first nine months of 2024, 100.0% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with underlying PPAs, as compared to 99.9% in the first nine months of 2023. This provides us with certainty of price resulting from our Renewable Electricity sites.

Expenses for the Nine Months Ended September 30, 2024 and 2023

General and Administrative Expenses

Total general and administrative expenses were $28,202 for the first nine months of 2024, an increase of $2,133 (8.2%) compared to $26,069 for the first nine months of 2023. Employee related costs, including stock-based compensation costs were $18,306 in the first nine months of 2024, an increase of $3,479 (23.5%) compared to $14,827 in the first nine months of 2023. The increase was primarily related to the accelerated vesting of certain restricted share awards as a result of the termination of an employee. Our professional fees decreased approximately $1,514 (40.0%) in the first nine months of 2024 compared to the first nine months of 2023.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in the first nine months of 2024 were $38,629, an increase of $3,669 (10.5%) as compared to $34,960 in the first nine months of 2023. Our Rumpke facility operating and maintenance expenses increased approximately $1,092 primarily related to media change outs and disposal costs. Our McCarty facility operating and maintenance expenses increased approximately $933 primarily related to a wellfield operational enhancement program. Our Atascocita facility operating and maintenance expenses increased approximately $905 primarily related to increased utility expense.

Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the first nine months of 2024 were $25,206, an increase of $1,109 (4.6%) compared to $24,097 in the first nine months of 2023. We recorded a reduction to our Pico facility earnout of approximately 10.0% during the first nine months of 2024. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 18.7 % for the first nine months of 2024 from 21.1% for the first nine months of 2023.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in the first nine months of 2024 were $9,712, an increase of $1,195 (14.0%) compared to $8,517 in the first nine months of 2023. Our Bowerman facility operating and maintenance expenses increased approximately $868 which was primarily driven by the timing of annual original equipment manufacturer preventative maintenance expenses. Our Magnolia facility operating and maintenance expenses increased approximately $840 as a result of non-capitalizable costs..

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the first nine months of 2024 were $1,496, an increase of $5 (0.3%) compared to $1,491 in the first nine months of 2023. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses increased to 11.1% from 10.8%.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in the first nine months of 2024 were $26,702, an increase of $1,114 (4.4%) compared to $25,588 in the first nine months of 2023. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.

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Depreciation

Depreciation and amortization in the first nine months of 2024 was $17,305, an increase of $1,513 (9.6%) compared to $15,792 in the first nine months of 2023. The increase was associated with timing of capital investment placed into service related to our Pico digestion capacity increase and Raeger capital improvement projects.

Impairment loss

We calculated and recorded impairment losses of $1,232 in the first nine months of 2024, an increase of $455 (58.6%) compared to $777 in the first nine months of 2023. The impairment losses in the first nine months of 2024 primarily relate to the remaining book value of assets at the Security facility, various RNG equipment that was deemed obsolete for current operations, and REG assets that were impacted under initial startup testing for one of our REG construction work-in-progress sites. The first nine months of 2023 impairment related to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use.

Other Expenses

Other expenses in the first nine months of 2024 was $3,036, a decrease of $305 (9.1%) compared to $3,341 in the first nine months of 2023. The decrease was primarily related to proceeds received from the sale of gas rights ahead of the fuel supply agreement expiration of our Security facility which offset increased interest expense of $604.

Income Tax Expense

Income tax expense for the nine months ended September 30, 2024 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily due discrete events related to stock compensation as compared to the year to date pre-tax book income.

The effective tax rate was 20.6% for the nine months ended September 30, 2024 and 20.9% for the nine months ended September 30, 2023 as a result of both periods having discrete events related to the vesting of restricted stock grants on stock compensation as compared to the year to date pre-tax book income.

Operating Income (Loss) for the Nine Months Ended September 30, 2024 and 2023

Operating income in the first nine months of 2024 was $25,944, an increase of $9,773 (60.4%) compared to $16,171 in the first nine months of 2023. RNG operating income for the first nine months of 2024 was $56,911, an increase of $14,104 (32.9%) compared to $42,807 in the first nine months of 2023. Renewable Electricity Generation operating loss for the first nine months of 2024 was $2,210, an increase of $2,086 (1,682.3%) compared to $124 for the first nine months of 2023.

Non-GAAP Financial Measures:

The following table presents EBITDA and Adjusted EBITDA, non-GAAP financial measures, for each of the periods presented below. We present EBITDA and Adjusted EBITDA because we believe the measures assist investors in analyzing our performance across reporting periods on a consistent basis by excluding items that we do not believe are indicative of our core operating performance. In addition, EBITDA and Adjusted EBITDA are financial measurements of performance that management and the board of directors use in their financial and operational decision-making and in the determination of certain compensation programs. EBITDA and Adjusted EBITDA are supplemental performance measures that are not required by or presented in accordance with GAAP. EBITDA and Adjusted EBITDA should not be considered alternatives to net income (loss) or any other performance measure derived in accordance with GAAP, or as an alternative to cash flows from operating activities or a measure of our liquidity or profitability.

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The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income, which is the most directly comparable GAAP measure, for the three months ended September 30, 2024 and 2023:



	For the three months ended September 30,
	2024		2023
Net income	$	17,048	$	12,934
Depreciation, depletion and amortization		6,048		5,346
Interest expense		1,835		1,295
Income tax expense		3,965		2,808
Consolidated EBITDA		28,896		22,383

Impairment loss (1)		533		51
Net loss on sale of assets		1		—
Adjusted EBITDA	$	29,430	$	22,434

(1)

We recorded impairment losses of $533 and $51 for the three months ended September 30, 2024 and 2023, respectively. The impairment losses in the third quarter of 2024 primarily relate to various RNG equipment that was deemed obsolete for current operations and REG assets that were impacted under initial startup testing for one of our REG construction work-in-progress sites. The third quarter of 2023 impairment relates to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and recorded in our RNG segment.


	For the nine months ended September 30,
	2024		2023
Net income	$	18,186	$	10,149
Depreciation, depletion and amortization		17,305		15,792
Interest expense		4,285		3,681
Income tax expense		4,722		2,681
Consolidated EBITDA		44,498		32,303

Impairment loss (1)		1,232		777
Net loss of sale of assets		72		37
Transaction costs		61		86
Adjusted EBITDA	$	45,863	$	33,203

(1)

We recorded impairment losses of $1,232 and $777 for the nine months ended September 30, 2024 and 2023, respectively. The impairment losses in the first nine months of 2024 primarily relate to the remaining book value of assets at the Security facility, various RNG equipment that was deemed obsolete for current operations, REG assets that were impacted under initial startup testing for one of our REG construction work-in-progress sites. The first nine months of 2023 impairment relates to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use.

Liquidity and Capital Resources

Sources of Liquidity

At September 30, 2024 and September 30, 2023, our cash and cash equivalents, net of restricted cash, was $54,973 and $73,304 respectively. We intend to fund development projects using cash flows from operations and borrowings under our revolving credit facility. We believe that we will have sufficient cash flows from operations and borrowing availability under our credit facility to meet our debt service obligations and anticipated required capital expenditures (including for projects under development) for the next 12 to 24 months. However, we are subject to business and operational risks that could adversely affect our cash flows and liquidity.

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At September 30, 2024, we had debt before debt issuance costs of $58,000, compared to debt before debt issuance costs of $64,000 at December 31, 2023.

Our debt before issuance costs (in thousands) are as follows:


	September 30, 2024		December 31, 2023
Term loan	$	58,000		64,000
Revolving credit facility		—		—
Debt before debt issuance costs	$	58,000	$	64,000

Amended Credit Agreement

On December 21, 2021, the Company entered into the Fourth Amendment with Comerica and certain other financial institutions. The current credit agreement, which is secured by a lien on substantially all of our assets and assets of certain of our subsidiaries, provides for a five-year $80,000 term loan, a five-year $120,000 revolving credit facility, and a $75,000 accordion feature.

As of September 30, 2024, $58,000 was outstanding under the term loan and we had no outstanding borrowings under the revolving credit facility. The term loan amortizes in quarterly installments of $2,000 through 2024, then increases to $3,000 through 2026, with a final payment of $32,000 in late 2026 with an interest rate of 6.12% and 6.11% at September 30, 2024 and December 31, 2023, respectively. The revolving and term loans under the Amended Credit Agreement bore interest at the BSBY plus an applicable margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement) as of September 30, 2024. The BSBY will cease on November 15, 2024, and the current debt agreement was amended to utilize the SOFR, plus an applicable margin.

The Amended Credit Agreement contains customary covenants applicable to us and certain of our subsidiaries, including financial covenants. The Amended Credit Agreement is subject to customary events of default, and contemplates that we would be in default if, for any fiscal quarter (x) the average monthly D3 RIN price (as determined in accordance with the Amended Credit Agreement) is less than $0.80 per RIN and (y) the consolidated EBITDA for such quarter is less than $6,000. Consolidated EBITDA is defined under the Amended Credit Agreement as net income plus (a) income tax expense, (b) interest expense, (c) depreciation, depletion, and amortization expense, (d) non-cash unrealized derivative expense and (e) any other extraordinary, unusual, or non-recurring adjustments to certain components of net income, as agreed upon by Comerica in certain circumstances.

Under the Amended Credit Agreement, we are required to maintain the following ratios:

•

a Total Leverage Ratio (as defined in the Amended Credit Agreement) of not more than 3.00 to 1.00 as of the end of any fiscal quarter from June 30, 2024 and thereafter; and

•

as of the end of each fiscal quarter, a Fixed Charge Coverage Ratio (as defined in the Amended Credit Agreement) of not less than 1.2 to 1.0.

As of September 30, 2024, we were in compliance with all applicable financial covenants under the Amended Credit Agreement.

The Amended Credit Agreement replaced our prior credit agreements with Comerica and a portion of the proceeds of the term loan made under the Amended Credit Agreement were used by us to, among other things, fully satisfy an aggregate of $59,197 outstanding principal under such credit agreements. For additional information regarding the Amended Credit Agreement, see Note 12— Debt to our unaudited condensed consolidated financial statements.

Capital Expenditures

We have historically funded our growth and capital expenditures with our working capital, cash flow from operations and debt financing. We expect our non-development 2024 capital expenditures to range between $14,000 and $16,000. Our 2024 capital plans include annual preventative maintenance expenditures, annual wellfield expansion projects, other specific facility improvements, and information technology improvements. Additionally, we currently estimate that our existing 2024 development capital expenditures will range between $55,000 and $65,000. The refinement in our 2024 development capital range is primarily related to the aforementioned delay of our Bowerman RNG Project. The majority of our 2024 development capital expenditures are related to our ongoing development of Montauk Ag Renewables, the second Apex facility, and the Bowerman RNG project. Our Amended Credit Agreement provides us with a $120,000 revolving credit facility, with a $75,000 accordion option, providing us with access to

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additional capital to implement our acquisition and development strategy. We are currently in various stages of discussions regarding a variety of strategic growth opportunities. Included amongst these opportunities are: approximately up to three LFG RNG, waste-water treatment RNG, and CNG distribution opportunities. If we ultimately enter into definitive agreements for any of these opportunities, we expect to incur material capital expenditures related to either acquisition costs or development costs, or both. As we continue to explore strategic growth opportunities and while we have entered into nonbinding letters of intent for certain of these opportunities, we provide no assurances that our plans related to any or all of these strategic opportunities will progress to definitive agreements. We believe that our existing cash and cash equivalents, cash generated from operations, and credit availability under our Amended Credit Agreement would allow us to pursue and close on our identified strategic growth opportunities in addition to the previously discussed non-development and development capital expenditures.

Cash Flow

The following table presents information regarding our cash flows and cash equivalents for the nine months ended September 30, 2024 and 2023:


	For the nine months ended September 30,
	2024			2023
Net cash provided by (used in):
Operating activities	$	43,071		$	19,587
Investing activities		(54,129	)		(45,404	)
Financing activities		(7,755	)		(6,054	)
Net decrease in cash and cash equivalents		(18,813	)		(31,871	)
Restricted cash, end of the period		456			431
Cash and cash equivalents, end of period		55,429			73,735

For the first nine months of 2024, we generated $43,071 of cash provided by operating activities compared to $19,587 in the first nine months of 2023. For the first nine months of 2024, income and adjustments to income from operating activities provided $46,737 compared to income and adjustments to income provided $35,915 in first nine months of 2023. Working capital and other assets and liabilities used $3,666 in the first nine months of 2024 compared to working capital and other assets and liabilities used $16,328 in the first nine months of 2023.

Our net cash flows used in investing activities has historically focused on project development and facility maintenance. Our capital expenditures for the first nine months of 2024 were $53,334, of which $24,977, $10,021, $7,871, $1,795, and $1,297 were related to the Montauk Ag Renewables in North Carolina, second Apex RNG facility, Bowerman RNG project, Blue Granite RNG project, and the Pico facility digestion capacity increase, respectively. We completed a land acquisition in Turkey, NC for 42 acres during the first nine months of 2024 for $820.

Our net cash flows used in financing activities of $7,755 for the first nine months of 2024 increased by $1,701 compared to cash used in financing activities in the first nine months of 2023 of $6,054.

Contractual Obligations and Commitments

Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under GAAP. Our off-balance sheet arrangements are limited to the outstanding letters of credit described below. Although these arrangements serve a variety of our business purposes, we are not dependent on them to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.

We have contractual obligations involving asset retirement obligations. See Note 8 in the unaudited condensed consolidated financial statements for further information regarding the asset retirement obligations.

We have contractual obligations under our debt agreement, including interest payments and principal repayments. See Note 12 in the unaudited condensed consolidated financial statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. During the first nine months of 2024, we had approximately $2,185 of off-balance sheet arrangements of outstanding letters of credit. These letters of credit reduce the borrowing capacity of our revolving credit facility under our Amended Credit Agreement. Certain of our contracts require these letters of credit to be issued to provide additional performance assurances. There have been no draw downs on these outstanding letters of credit. During the first nine months of 2023, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $2,505.

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We have contractual obligations involving operating leases. We lease office space and other office equipment under operating lease arrangements, expiring in various years through 2033. See Note 18 in the unaudited condensed consolidated financial statements for further information related to the lease obligations.

We have other contractual obligations associated with our fuel supply agreements. The expiration of these agreements range between 3-19 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,645.

Critical Accounting Policies and Estimates

Our unaudited condensed consolidated financial statements are prepared in conformity with GAAP and require our management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, costs and expenses and related disclosures. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and such estimates may change if the underlying conditions or assumptions change.

Revenue Recognition

Our revenues are comprised of renewable energy and the related Environmental Attribute sales provided under a variety of short-term and medium-term agreements with our customers. All revenue is recognized when we satisfy our performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product to the customer either when (or as) the customer obtains control of the product. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. We allocate the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract.

Revenue is measured as the amount of consideration we expect to receive in exchange for transferring our products. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred. To the extent applicable, sales, value add, and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.

RINs

We generate D3 RINs through our production and sale of RNG used for transportation purposes as prescribed under the RFS program. Our operating costs are associated with the production of RNG. The RINs are government incentives that are generated through our renewable operating projects and not a result of physical attributes of our RNG production. The RINs that we generate are able to be separated and sold as credits independently from the energy produced. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred. We enter into forward commitments to transfer RINs. These forward commitments are based on D3 RIN index prices at the time of the commitment. Realized prices for RINs monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

RECs

We generate RECs through our production and conversion of landfill methane into Renewable Electricity in various states, including California, Oklahoma, and Texas. These states have various laws requiring utilities to purchase a portion of their energy from renewable resources. Our operating costs are associated with the production of Renewable Electricity. The RECs are generated as an output of our renewable operating projects. The RECs that we generate are able to be separated and sold independently from the electricity produced. Therefore, no cost is allocated to the REC when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred.

Income Taxes

We are subject to income taxes in the U.S. federal jurisdiction and various state and local jurisdictions. Tax regulations within each jurisdiction are subject to the interpretation of the related tax laws and regulations and require significant judgment to apply.

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Our net deferred tax asset position is a result of fixed assets, intangibles, and tax credit carryforwards. The realization of deferred tax assets is dependent upon our ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in our financial statements or tax returns and forecasting future profitability by tax jurisdiction.

We evaluate our deferred tax assets at reporting periods on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of our deferred tax assets. We account for uncertain tax positions using a “more-likely-than-not” threshold for recognizing and resolving uncertain tax positions. The evaluation of uncertain tax positions is based on factors that include, but are not limited to, changes in tax law, the measurement of tax positions taken or expected to be taken in tax returns, the effective settlement of matters subject to audit, new audit activity and changes in facts or circumstances related to a tax position.

Intangible Assets

Separately identifiable intangible assets are recorded at their fair values upon acquisition. We account for intangible assets in accordance with ASC 350, Intangibles—Goodwill and Other. Finite-lived intangible assets include interconnections, customer contracts, and trade names and trademarks. The interconnection intangible asset is the exclusive right to utilize an interconnection line between the operating project and a utility substation to transmit produced electricity. Included in that right is full maintenance provided on this line by the utility. Intangible assets with finite useful lives are amortized on a straight-line basis over their estimated useful life. We evaluate our finite-lived intangible assets for impairment as events or changes in circumstances indicate the carrying value of these assets may not be fully recoverable. Events that could result in an impairment include, among others, a significant decrease in the market price or the decision to close a site.

If finite-lived or indefinite-lived intangible assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. The fair value is determined based on the present value of expected future cash flows. We use our best estimates in making these evaluations, however, actual future pricing, operating costs and discount rates could vary from the assumptions used in our estimates and the impact of such variations could be material.

Our assessment of the recoverability of finite-lived and indefinite-lived intangible assets is determined by performing monitoring assessment of the future cash flows associated with the underlying gas rights agreements. The cash flows estimates are performed at the operating unit level and based on the average remaining length of the gas rights agreements. Based on our analysis, we concluded the cashflows generated to be well in excess of the carrying amounts. Changes in market conditions related to the various price indexes used in estimating these cash flows could adversely affect these estimates.

Finite-Lived Asset Impairment

In accordance with FASB ASC Topic 360, Property, Plant and Equipment and intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results, including considering project specific assumptions for long-term credit prices, escalated future project operating costs and expected site operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Fair value is generally determined by considering (i) internally developed discounted cash flows for the asset group, (ii) third-party valuations, and/or (iii) information available regarding the current market value for such assets. We use our best estimates in making these evaluations and consider various factors, including future pricing and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates and the impact of such variations could be material. We identified discrete events and recorded impairment of $1,232 and $777 for the nine months ended September 30, 2024 and 2023, respectively. See Note 3 in the unaudited condensed consolidated financial statements for further information related to asset impairments.

Emerging Growth Company

We are an emerging growth company, as defined in the JOBS Act. The JOBS Act allows emerging growth companies to delay the adoption of new or revised accounting standards until such time as those standards apply to private companies. We intend to utilize

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these transition periods, which may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the transition periods afforded under the JOBS Act.

Recent Accounting Pronouncements

For a description of our recently adopted accounting pronouncements and recently issued accounting standards not yet adopted, see Note 2 of our unaudited condensed consolidated financial statements in this report.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes since our disclosure in Quantitative and Qualitative Disclosures About Market Risk included as Item 7A in our 2023 Annual Report.

ITEM 4. CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act, as of the end of the period covered by this quarterly report. Disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Our management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Our management, including our principal executive officer and principal financial officer, after evaluating the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report, concluded that as of such date, our disclosure controls and procedures were effective at a reasonable level of assurance.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during our most recent fiscal quarter that have 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

From time to time, we and our subsidiaries may be parties to legal proceedings arising in the normal course of our business. We and our subsidiaries are currently not a party, nor is our property subject, to any material pending legal proceedings.

ITEM 1A. RISK FACTORS

We face a number of risks that could materially and adversely affect our business, results of operations, cash flow, liquidity, or financial condition. A discussion of our risk factors can be found in Part I, “Item 1A Risk Factors” in our 2023 Annual Report any of which could have a material effect on us.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Use of Proceeds from Sale of Registered Securities

On January 21, 2021, our Registration Statement on Form S-1, as amended (File No. 333-251312) (the “Registration Statement”), was declared effective by the SEC in connection with our IPO. The underwriter for the IPO was Roth Capital Partners. A total of 3,399,515 shares of our common stock were sold pursuant to the Registration Statement, which was comprised of (1) 2,702,500 shares of new common stock issued by the Company and (2) 697,015 shares of the Company’s common stock held by MNK. The 3,399,515 shares were sold at an offering price of $8.50 per share and resulting in net proceeds to the Company of approximately $15.0 million, after deducting the underwriting discount of approximately $1.6 million and offering expenses payable by the Company of approximately $6.2 million.

The IPO closed on January 26, 2021. No payments for such expenses were made directly or indirectly to (i) any of our officers or directors or their associates, (ii) any persons owning 10% or more of any class of our equity securities or (iii) any of our affiliates.

From the closing of the IPO through March 31, 2024, approximately $15.0 million of the net proceeds from the IPO have been used by Montauk for the following: the Montauk Ag Asset Acquisition in May 2021, the purchase of the real-estate and property in October 2021 related to Montauk Ag, and subsequent development activities related to Montauk Ag Renewables. An immaterial amount has been used relating to other possible acquisitions and projects. As of March 31, 2024, all net proceeds were used by the Company.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS


Exhibit Number		Description



10.14		Fifth Amendment to Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of November 8, 2024 by and among Montauk Energy Holdings, LLC, the financial institutions from time to time signatory thereto and Comerica Bank, as Administrative Agent

31.1		Certification of the Chief Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) of the Securities Exchange Act

31.2		Certification of the Chief Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) of the Securities Exchange Act

32.1		Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS		Inline XBRL Instance Document–the instance document does not appear in the Interactive Data File as its XBRL tags are embedded within the Inline XBRL document

101.SCH		Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents

104		Cover page formatted as Inline XBRL and contained in Exhibit 101

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


November 12, 2024	MONTAUK RENEWABLES, INC.

	By:	/s/ SEAN F. MCCLAIN
		Sean F. McClain
		President and Chief Executive Officer (Principal Executive Officer)

	By:	/s/ KEVIN A. VAN ASDALAN
		Kevin A. Van Asdalan
		Chief Financial Officer (Principal Accounting Officer)