Montauk Renewables, Inc. (MNTK) FY 2022 MD&A
This page reproduces the company's own Item 7 MD&A text from the linked SEC filing. It is filer text, not grepcent analysis, scoring, or investment advice.
Overview
Montauk 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 three Renewable Electricity projects through self-development, partnerships, and acquisitions that span six 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 and ADG, which is produced inside an airtight tank used to breakdown organic matter, such as livestock waste. 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 short-, medium-, and long-term 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 initiatives.
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 industry experienced volatile D3 RIN index prices since the EPAs release of the 2023 RVO in December 2022. Though the average market price of D3 RINs since the 2023 RVO release was approximately $2.18, the market price declined as low as $1.88 in February 2023 from a D3 RIN index price of $2.43 on the day of the 2023 RVO release. We viewed this reduction in price as temporary and, accordingly, we determined not to transfer a significant amount of D3 RINs generated and available for transfer during the first quarter of 2023. As a result, we have approximately 3,890 RINs in inventory from 2022 gas production and have approximately 7,269 RINs in inventory from 2023 gas production as of the filing of this Report.
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We have not entered into commitments to transfer these RINs in inventory nor have we entered into agreements to transfer future RINs generated from forecasted future production. The average D3 RIN index price during the month of February 2023 was approximately $1.95.
Montauk Ag Asset 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 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, bio-oil and biochar (the “Montauk Ag Renewables Acquisition”). The assets acquired include real property, intellectual property, mobile equipment, and other equipment related to operating the business. The real property includes the purchase of an approximate 9.35 acre parcel in Duplin County, North Carolina. Also, in 2021, we closed on a transaction to acquire approximately 146 acres and an approximately 500,000 square foot existing structure in Turkey, North Carolina where we plan to use consolidate and expand the production processes purchased in the Montauk Ag Renewables Acquisition.
We continue to work with our engineer of record through the optimization of improvements to the now patented reactor technology. However, we have not completed our improvements, and we have not reached commercial operations at the Turkey, NC location. The improvements to the reactor technology are intended to be deployed at the Turkey, NC location. During the fourth quarter of 2022 we began to relocate the reactor in Magnolia, NC to the Turkey, NC location to centralize processing at one location. As part of the centralization and in connection with the optimization of the reactor, we assessed various assets of the Magnolia, NC reactor as no longer being applicable to the improved reactor process. As a result, we recorded an impairment charge of approximately $1,393 related to assets originally acquired in the May 2021 Montauk Ag Renewables Acquisition we determined were no longer usable.
While these project developments continue, we continue to engage with regulatory agencies in North Carolina related to the resulting power generation derived from swine waste to confirm its eligibility for Renewable Energy Credits under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production. Accordingly, we requested that our Turkey location be approved to participate in the Piedmont Natural Gas Renewable Gas Pilot Program which is a step towards obtaining the New Renewable Energy Facility (“NREF”) designation under the North Carolina Utilities Commission. Due to our consolidation of operations at the Turkey, NC location and based on our current expectations related to commercial operations, we have paused our registration process to obtain NREF status for the Turkey, NC location. Our Turkey, NC location has been accepted into the Piedmont Natural Gas Renewable Gas Pilot Program.
In the first quarter of 2023 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. We are also in varying stages of discussions with potential power purchasers.
We are at the beginning stages of developing the opportunities associated with Montauk Ag Renewables and can give no assurances that our plans related to this acquisition will meet our expectations. We continue to design and plan for the development of the facility to be used for commercial production. Based on our current development timeline expectations, we do not expect to commence significant revenue generating activities until 2024. We intend to contract with additional farms to secure feedstock sources for future production processes.
Amendment to Pico Feedstock Agreement
During the second quarter of 2021, we completed an amendment to our Pico feedstock agreement (“Pico Feedstock Amendment”). The amendment will increase the amount of feedstock supplied to the facility for processing over a one to three-year period. We have paid $3,500 in cash under the terms of the Pico Feedstock Amendment.
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Under the Pico Feedstock Amendment the dairy began delivering the first and second increases in feedstock during the third quarter of 2022. The improved efficiencies of our existing digestion process and the water management improvements have enabled us to process the increased feedstock volumes which we currently expect to increase by five to ten percent once all increased feedstock deliveries have been received from the dairy. We completed the design of the digestion capacity project in the third quarter of 2022 and have begun incurring capital expenditures related to the construction of the project. We currently expect the construction project to be functionally completed during the third quarter of 2023. We currently expect the dairy to begin delivering the final increase in feedstock volumes during 2024.
In the first quarter of 2023, CARB finalized the engineering review of the Pico facility’s provisional CI application and released it for public comment. The public comment period ended March 14, 2023. We do not believe we received any significant public comments and expect to receive the certified provisional CI score before the end of the first quarter of 2023.
Second Apex RNG Facility
In August 2022, we announced the planned construction of a second RNG processing facility at the Apex landfill. This project is being driven by projections in biogas feedstock availability from the host landfill. We anticipate an approximate 40% increase in RNG processing capacity with the addition of the second facility. This expansion is expected to increase daily production approximately 2,100 MMBtu per day and expand the infrastructure for the conversion of LFG to RNG. We have begun to incur capital expenditures for this project and expect the project to be complete and become commercially operational in 2024.
Raeger Capital Improvement
In June 2022, our Board of Directors approved a capital improvement project to make upgrades to our Raeger facility that will increase production. This facility is currently being impacted by requirements to meet federal pipeline tariffs which limit the oxygen content of product gas. The pipeline tariffs have resulted in limitations in our ability to process all existing feedstock. During the second quarter of 2022, we completed our analysis of process facility improvements necessary to meet these more stringent tariff requirements. Construction on this capital project commenced during the third quarter of 2022 and we expect it will become commercially operational during the second half of 2023. Based on the current production of the Raeger facility, we anticipate an approximate increase of 50% of average daily production.
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:
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| • | Regulatory or policy initiatives, including the federal RFS program and state-level low-carbon fuel programs in states such as California and Oregon, that drive demand for RNG and its derivative Environmental Attributes (as further described below). |
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| • | Efficiency, mobility and capital cost flexibility in RNG operations enable it 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 equivalents. |
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| • | 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. |
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| • | 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 periodically evaluate opportunities to convert existing 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 sale of RNG plus RINs relative to the sale of market rate electricity plus 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:
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| • | 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. Further, the receipt of RINs is delayed, and typically does not commence for a period of four to six months after the commencement of injecting RNG into a pipeline, pending final registration approval of the project by the EPA and then the subsequent completion of a third-party quality assurance plan certification. During such time, the RNG is either physically or theoretically stored and later withdrawn from storage to allow for the generation of RINs. |
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| • | 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 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.
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| • | 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. In accordance with the consent decree entered into between the EPA and Growth Energy approved by the U.S. District Court for the District of Columbia, the EPA issued the final Renewable Fuel Standards for 2020, 2021, and 2022 on June 3, 2022. Final volumes for cellulosic biofuel were set at 510, 560 and 630 million RINs for the three years 2020, 2021 and 2022, respectively. While final volumes set for all three years were lower than proposed, the EPA partially offset the lower volumes by issuing its final notice, also on June 3, 2022, to deny the remaining 69 petitions for RFS Small Refinery Exemptions. Per the settlement agreement with Growth Energy, the EPA was
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required to issue a proposed 2023 RVO no later than November 16, 2022 with final volume requirements established by June 11, 2023. On November 4, 2022, the EPA filed a notice with the U.S. District Court for the District of Columbia indicating that EPA and Growth Energy have agreed to extend the deadline for signing the proposed rule for the 2023 renewable fuel standards.
The EPA issued the proposed Renewable Fuel Standard for 2023, 2024, and 2025 on December 1, 2022. Comments on this proposed rule were due by February 10, 2023 with a final rule to be issued by June 14, 2023. The proposed volumes for cellulosic biofuel were set at 720, 1,420, and 2,130 million RINs for the three years 2023, 2024, and 2025, respectively. Included within these volumes are 0, 600, and 1,200 million volumes of eRINs generated from renewable electricity for 2023, 2024, and 2025, respectively.
Changes to 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. CARB finalized engineering review of the Pico facility’s provisional CI application and posted the application for public comment on February 28, 2023. The public comment period ended March, 14, 2023. We expect to receive the certified provisional CI score before the end of the first quarter of 2023.
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 entity 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 monetize a portion of our RNG production under fixed-price agreements which provide floor prices in excess of commodity indices. |
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| • | 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. |
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| • | Corporate Revenues: Corporate reports realized and unrealized gains or losses under our 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 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.
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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, 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.
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| • | In October 2020, California wildfires forced our Bowerman facility to temporarily shut down. While production resumed in November 2020, our fourth quarter 2020 Bowerman revenues were approximately 20.0% lower than the prior year period. Operations at this facility have resumed. |
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| • | A 2021 cold weather event impacted our Atascocita, Galveston, McCarty, and Coastal Plains facilities located in Texas. Production at these facilities was temporarily idled due to the loss of power from February 14 through February 20, 2021 and force majeure events were declared by certain of our counter-parties or by us for the period February 12 through February 22, 2021 related to these weather events. Operations at these facilities have resumed. |
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| • | The landfill host at our McCarty facility recently changed its wellfield collection system which 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 the facility. We are working with the landfill host but have currently experienced lower volumes of feedstock available to be processed at the McCarty facility. We experienced lower than historical volumes beginning in 2022. |
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| • | Our Pico facility has resumed operations and we expect all ramp up activities to be completed by the second quarter of 2022. Our improvement project has impacted the timeline related to modeling the CI Score pathway model. 2022 production will be stored until CARB completes its CI Score Pathway. We currently expect to receive LCFS credit revenue on 2022 production until 2023. |
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| • | Many of our sites were impacted by severe cold weather events occurring during the fourth quarter of 2022. In anticipation of these events, we implemented winterization programs designed to protect our processing equipment from these cold weather events. These programs included draining water and adding temporary insulation and heat trace at certain sites. Even with our winterization efforts, we experienced lower than historical production volumes during December 2022 due to this severe cold weather. Operations at these facilities have subsequently resumed. |
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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, 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. |
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| • | 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 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
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produce. We sell the RNG produced from our projects under a variety of short-term and medium-term 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.
Our dairy farm project is expected to be awarded a more attractive CI by CARB, thereby generating LCFS credits at a multiple of those generated by our landfill projects.
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, although currently we only sell RINs in the calendar year they are generated in the following calendar year. We did not forward sell a significant portion of expected 2023 RIN generation. 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.
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| • | 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. |
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| • | 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. |
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| • | 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 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 2023. The Company accounts for stock-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. For more information, see Note 15 to our audited consolidated financial statements. |
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| • | 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. |
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| • | 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:
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| • | 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 schedule 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. |
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| • | 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, though a portion are generated and monetized by third parties under counterparty sharing agreements. A majority of our Renewable Electricity Generation segment Environmental Attributes are monetized as a component of our fixed-price PPAs. |
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| • | 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. We may elect to not commit to transfer all available RINs in a given period which could impact our revenue and operating profit. 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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The following table summarizes the key operating metrics described above, which metrics we use to measure performance.
| (in thousands, unless otherwise indicated) | For the year ended December 31, | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2022 | 2021 | Change | Change % | |||||||||||||
| Revenues | ||||||||||||||||
| Renewable Natural Gas Total Revenues | $ | 196,218 | $ | 131,803 | $ | 64,415 | 48.9 | % | ||||||||
| Renewable Electricity Generation Total Revenues | $ | 17,170 | $ | 15,449 | $ | 1,721 | 11.1 | % | ||||||||
| RNG Metrics | ||||||||||||||||
| CY RNG production volumes (MMBtu) | 5,522 | 5,688 | (166 | ) | (2.9 | )% | ||||||||||
| Less: Current period RNG volumes under fixed/floor-price contracts | (1,278 | ) | (1,596 | ) | 318 | (19.9 | )% | |||||||||
| Plus: Prior period RNG volumes dispensed in current period | 372 | 353 | 19 | 5.4 | % | |||||||||||
| Less: Current period RNG production volumes not dispensed | (378 | ) | (372 | ) | (6 | ) | 1.6 | % | ||||||||
| Total RNG volumes available for RIN generation(1) | 4,238 | 4,073 | 165 | 4.1 | % | |||||||||||
| RIN Metrics | ||||||||||||||||
| Current RIN generation ( x 11.727)(2) | 49,697 | 47,758 | 1,939 | 4.1 | % | |||||||||||
| Less: Counterparty share (RINs) | (5,275 | ) | (5,124 | ) | (151 | ) | 2.9 | % | ||||||||
| Plus: Prior period RINs carried into CY | 140 | 110 | 30 | 27.3 | % | |||||||||||
| Less: CY RINs carried into next CY | (739 | ) | (140 | ) | (599 | ) | 427.9 | % | ||||||||
| Total RINs available for sale(3) | 43,823 | 42,604 | 1,219 | 2.9 | % | |||||||||||
| Less: RINs sold | (43,823 | ) | (42,604 | ) | (1,219 | ) | 2.9 | % | ||||||||
| RIN Inventory | — | — | — | — | ||||||||||||
| RNG Inventory (volumes not dispensed for RINs)(4) | 368 | 372 | (4 | ) | (1.1 | )% | ||||||||||
| Average Realized RIN price | $ | 3.25 | $ | 1.91 | $ | 1.34 | 70.2 | % | ||||||||
| Operating Expenses | ||||||||||||||||
| Renewable Natural Gas Operating Expenses | $ | 86,068 | $ | 65,046 | $ | 21,022 | 32.3 | % | ||||||||
| Operating Expenses per MMBtu (actual) | $ | 15.59 | $ | 11.44 | $ | 4.15 | 36.3 | % | ||||||||
| Renewable Electricity Generation Operating Expenses | $ | 14,910 | $ | 12,177 | $ | 2,733 | 22.4 | % | ||||||||
| $/MWh (actual) | $ | 78.47 | $ | 66.56 | $ | 11.91 | 17.9 | % | ||||||||
| Other Metrics | ||||||||||||||||
| Renewable Electricity Generation Volumes Produced (MWh) | 190 | 183 | 7 | 3.8 | % | |||||||||||
| Average Realized Price $/MWh (actual) | $ | 90.37 | $ | 84.45 | $ | 5.92 | 7.0 | % |
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| (1) | RINs are generated in the month that the gas 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. |
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| (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. |
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| (3) | Represents RINs available to be self-marketed by us during the reporting period. |
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| (4) | Represents gas production which has not been dispensed to generate RINs. |
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Results of Operations
Comparison of Years Ended December 31, 2022 and 2021
The following table summarizes our revenues, expenses and net income for the periods set forth below:
| (in thousands, except per share data) | For the year ended December 31, | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2022 | 2021 | Change | Change% | |||||||||||||
| Total operating revenues | $ | 205,559 | $ | 148,127 | $ | 57,432 | 38.8 | % | ||||||||
| Operating Expenses: | ||||||||||||||||
| Operating and maintenance expenses | 57,267 | 49,477 | 7,790 | 15.7 | % | |||||||||||
| General and administrative expenses | 34,139 | 42,552 | (8,413 | ) | (19.8 | )% | ||||||||||
| Royalties, transportation, gathering and production fuel | 44,163 | 28,683 | 15,480 | 54.0 | % | |||||||||||
| Depreciation and amortization | 20,700 | 22,869 | (2,169 | ) | (9.5 | )% | ||||||||||
| Gain on insurance proceeds | (313 | ) | (332 | ) | 19 | (5.7 | )% | |||||||||
| Impairment loss | 4,852 | 1,191 | 3,661 | 307.4 | % | |||||||||||
| Transaction costs | 185 | 352 | (167 | ) | (47.4 | )% | ||||||||||
| Total operating expenses | $ | 160,993 | $ | 144,792 | $ | 16,201 | 11.2 | % | ||||||||
| Operating profit | $ | 44,566 | $ | 3,335 | $ | 41,231 | 1236.3 | % | ||||||||
| Other expenses: | 1,324 | 3,702 | (2,378 | ) | (64.2 | )% | ||||||||||
| Income tax expense | 8,048 | 4,161 | 3,887 | 93.4 | % | |||||||||||
| Net income (loss) | $ | 35,194 | $ | (4,528 | ) | $ | 39,722 | 877.3 | % |
Revenues for the Years Ended December 31, 2022 and 2021
Total revenues in 2022 were $205,559, an increase of $57,432 (38.8%) compared to $148,127 in 2021. The primary driver for this increase relates to an increase of 70.2% in realized RIN pricing during 2022 of $3.25 compared to $1.91 in 2021. Additionally, the natural gas index price increased approximately 72.9% in 2022 and was $6.64 compared to $3.84 in 2021. These increases were offset by lower counterparty sharing revenues of $13,176 in 2022 compared to 2021 due to these arrangements ending.
Renewable Natural Gas Revenues
We produced 5,522 MMBtu of RNG during 2022, a decrease of 166 MMBtu (2.9%) from the 5,688 MMBtus produced in 2021. Our Atascocita facility produced 160 fewer MMBtu in 2022 compared to 2021 due to a temporary process equipment failure. Our Rumpke facility produced 89 fewer MMBtu in 2022 compared to 2021 as a result of lower wellfield inlet flow associated with the landfill host operations. Our Apex facility produced 70 fewer MMBtu in 2022 compared to 2021 due to landfill filling pattern changes resulting in lower production. Offsetting the decrease are production volume increases at our Pico and Galveston facilities. Our Pico facility produced 108 MMBtu more in 2022 compared to 2021 as a result of improvements related to the existing digestion process and our water management practices. Our Galveston facility produced 52 MMBtu more in 2022 compared to 2021 as a result of higher inlet gas due to wellfield changes and plant efficiency optimization of process equipment.
Revenues from the Renewable Natural Gas segment in 2022 were $196,218, an increase of $64,415 (48.9%) compared to $131,803 in 2021. Average commodity pricing for natural gas for 2022 was 72.9% higher than the prior year. During 2022, we self-marketed 43,823 RINs, representing a 1,219 increase (2.9%) compared to 42,604 in 2021. The increase was primarily related to an offtake agreement change in 2021 providing more RNG volumes available to self-market. Average pricing realized on RIN sales during 2022 was $3.25 as compared to $1.91 in 2021, an increase of 70.2%. This compares to the average D3 RIN index price for 2022 of $2.98 being approximately 1.3% lower than the average D3 RIN index price in 2021 of $3.02. All our RIN sales in 2022 and
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2021 were priced generally on the D3 index with none based on CWC. At December 31, 2022, we had approximately 0.4 million MMBtus available for RIN generation and had approximately 0.7 million RINs generated and unsold. We had approximately 0.4 million MMBtus available for RIN generation and approximately 0.1 million RINs generated and unsold at December 31, 2021.
Renewable Electricity Generation Revenues
We produced 190 MWh in Renewable Electricity in 2022, an increase of approximately 7 MWh (3.8%) compared to 183 MWh in 2021. In 2022, our Security facility produced 10 MWh in 2022 compared to zero production in 2021 as a result of the prior period engine restoration project. Offsetting this increase, is a decrease at our Tulsa facility that produced 3 MWh less in 2022 compared to 2021 due to reduced feedstock availability at the landfill.
Revenues from Renewable Electricity facilities in 2022 were $17,170, an increase of $1,721 (11.1%) compared to $15,449 in 2021. Our Bowerman facility contributed to $1,244 of the increase, which was primarily driven by a temporary shutdown of the facility in the fourth quarter 2020 due to the California wildfires, resulting in $598 in reduced Environmental Attribute revenues in 2021 compared to 2022. Also contributing to the increase is our Security facility engine restoration project resulting in $668 in higher revenues for 2022 compared to zero in 2021.
Corporate Analysis
During 2022, our gas commodity hedge was priced at rates below actual index prices and we recorded losses of $7,829 related to our gas commodity hedge. Our gas commodity hedge expired in December 2022 and we did not have any gas commodity hedges during 2021. During 2021, we recorded revenues of $875 related to RINs purchased in 2021 and recorded an adjustment of $710, associated with our purchase of RINs, to reduce the carrying value of those RINs to net realizable value. This is included within our operating revenues in the Consolidated Statement of Operations for the 2021 period. We did not have market purchased RINs during 2022.
Expenses for the Years Ended December 31, 2022 and 2021
General and Administrative Expenses
Total general and administrative expenses of $34,139 in 2022, a decrease of $8,413 (19.8%) compared to $42,552 in 2021. Employee related costs, including stock-based compensation, decreased approximately $10,643 (35.4%) in 2022 compared to 2021. The decrease is primarily related to our accounting for the cancellation of MNK options and January 2021 grants of restricted stock, non-qualified stock options, and restricted stock units to the Company’s employees. Offsetting this decrease is an increase in general and administrative expenses of approximately $3,608 (337.5%) in 2022 as compared to 2021 associated with the Montauk Ag Renewables Acquisition. Our corporate insurance premiums increased approximately $377 (6.8%) during 2022 compared to 2021, primarily related to premium increases. Our board of directors approved payments of cash fees to non-employee directors resulting in increased fees of approximately $675 in 2022 as compared to 2021. Finally, excluding the Montauk Ag Renewables Acquisition, our professional fees increased approximately $799 (19.4%) in 2022 as compared to 2021 primarily related to increased legal fees.
Renewable Natural Gas Expenses
Operating and maintenance expenses for our RNG facilities in 2022 were $43,729, an increase of $5,615 (14.7%) compared to $38,114 in 2021. The increase is driven by increased RNG utilities of approximately $6,061 (61.2%) in 2022 compared to 2021. The increase was caused by a cold weather event in the first quarter of 2021 impacting our Houston based facilities being favorably impacted by lower utility rates.
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Royalties, transportation, gathering and production fuel expenses for the Company’s RNG facilities for 2022 were $42,339, an increase of $15,407 (57.2%) compared to $26,932 in 2021. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 21.6% for 2022 from 20.4% in 2021.
Renewable Electricity Expenses
Operating and maintenance expenses for our Renewable Electricity facilities in 2022 were $13,086, an increase of $2,660 (25.5%) compared to $10,426 in 2021. The increase is primarily driven by the timing of scheduled engine preventative maintenance intervals at our Bowerman facility, of approximately $1,645 higher in 2022 over 2021. Adding to the increase are operating expenses of approximately $434 related to Montauk Ag Renewables Acquisition.
Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for 2022 were $1,824, an increase of $73 (4.2%) compared to $1,751 in 2021 and as a percentage of Renewable Electricity Generation segment, revenues decreased from 11.3% to 10.6%.
Royalty Payments
Royalties, transportation, gathering, and production fuel expenses in 2022 were $44,163, an increase of 15,480 (54.0%) compared to $28,683 in 2021. 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 2022 were $20,700, a decrease of $2,169 (9.5%) compared to $22,869 in 2021. The decrease is associated with assets remaining in service being fully amortized.
Impairment loss
We calculated and recorded impairment losses of $4,852 for 2022, an increase of $3,661 (307.4%) compared to $1,191 for 2021. The primary driver of this increase relates to an impairment of $2,133 for a REG site wherein the forecast future cash flows did not exceed the carrying value of the site’s long lived assets. A second REG site was impaired for $1,393 due to discrete conclusion that certain assets acquired in the May 2021 Montauk Ag Renewables Acquisition would no longer be utilized. Also in 2022, we recorded an impairment at an RNG facility for approximately $1,108 due to the specific identification of certain assets no longer being capable of use as designed. The 2021 impairment loss of $1,191 was primarily related to the closure of two REG sites and the disposal of machinery at one RNG site.
Other Expenses (Income)
Other expenses in 2022 were $1,324, a decrease of $2,378 (64.2%) compared to $3,702 in 2021. Reduced interest expense of $1,136 is related to our favorable interest rate swap contract resulting in reduction of interest expense in 2022 as compared to 2021. Also impacting the decrease is $865 relating to asset disposal costs at our Galveston and Pico facilities in 2021.
Income Tax Expense
Prior to 2022, we generated NOLs, which can be carried forward indefinitely, however, some of the NOLs are under an 80% limitation. In 2022, we utilized all non-limited NOL carryforwards. Based upon our historical
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pre-tax book income and forecasts, we expect to utilize some remaining NOLs and thus have not recorded a valuation allowance against such NOLs.
Our effective income tax rate (“ETR”) for 2022 was an expense of 18.6% compared to 1,132.1% for the prior year period. The higher ETR in the prior year period was driven by the low pre-tax income compared to the tax expense of $4,161 for 2021, which was primarily driven by the Section 162(m) limitation.
The Inflation Reduction Act of 2022, enacted by the United States on August 16, 2022, did not have a material impact on our provision for income taxes for the year ended December 31, 2022. The American Rescue Plan Act of 2021, enacted on March 11, 2021 did not have a material impact on the provision for income taxes for the year ended December 31, 2021. The Company is continuing to analyze the ongoing impact of the Inflation Reduction Act legislation.
Operating Profit (Loss) for the Years Ended December 31, 2022 and 2021
Operating profit in 2022 was $44,566, an increase of $41,231 (1236.3%) compared to $3,335 in 2021. RNG operating profit for 2022 was $94,439, an increase of $44,089 (87.6%) compared to $50,350 in 2021. Renewable Electricity Generation operating loss for 2022 was $7,019, an increase of $3,929 (127.2%) compared to an operating loss of $3,090 in 2021.
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 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.
The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income:
| Year Ended December 31, | ||||||||
|---|---|---|---|---|---|---|---|---|
| 2022 | 2021 | |||||||
| Net income (loss) | $ | 35,194 | $ | (4,528 | ) | |||
| Depreciation and amortization | 20,700 | 22,869 | ||||||
| Interest expense | 1,792 | 2,928 | ||||||
| Income tax expense | 8,048 | 4,161 | ||||||
| Consolidated EBITDA | 65,734 | 25,430 | ||||||
| Impairment loss(1) | 4,852 | 1,191 | ||||||
| Net (gain) loss on sale of assets | (233 | ) | 822 | |||||
| Transaction costs | 185 | 352 | ||||||
| Loss on extinguishment of debt | — | 154 | ||||||
| Adjusted EBITDA | $ | 70,538 | $ | 27,949 |
| Column 1 | Column 2 |
|---|---|
| (1) | For the year ended December 31, 2022, we recorded an impairment of $2,133 for a REG site wherein the forecast future cash flows did not exceed the carrying value of the site’s long lived assets. A second REG |
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| Column 1 | Column 2 |
|---|---|
| site was impaired for $1,393 due to discrete conclusion that certain assets acquired in the May 2021 Montauk Ag Renewables Acquisition would no longer be utilized. Also in 2022, we recorded an impairment at an RNG facility for approximately $1,108 due to the specific identification of certain assets no longer being capable of use as designed. For year ended December 31, 2021, we recorded an impairment of $626 related to a landfill host request to decommission a previously converted RNG site. We were previously contractually obligated to maintain this facility. Additionally, we impaired $421 related to disposal of machinery at our Rumpke facility. |
Liquidity and Capital Resources
Sources of Liquidity
At December 31, 2022 and 2021, our cash and cash equivalents, net of restricted cash, was $105,177 and $53,266, 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.
At December 31, 2022, we had debt before debt issuance costs of $72,000, compared to debt before debt issuance costs of $80,000 at December 31, 2021.
Our debt before issuance costs (in thousands) is as follows:
| December 31, 2022 | December 31, 2021 | ||||||
|---|---|---|---|---|---|---|---|
| Term Loans | $ | 72,000 | $ | 80,000 | |||
| Revolving Credit Facility | — | — | |||||
| Debt before debt issuance costs | $ | 72,000 | $ | 80,000 |
Amended Credit Agreement
On December 21, 2021, the Company entered into the Fourth Amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement (the “Amended Credit Agreement”), with Comerica Bank (“Comerica”) and certain other financial institutions. The Amended Credit Agreement, which is secured by substantially all of our assets and assets of certain of our subsidiaries, provides for a five-year $80,000 term loan and a five-year $120,000 revolving credit facility.
As of December 31, 2022, $72,000 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 December 2024, quarterly installments of $3,000 from 2025 through the maturity, with a final payment of $32,000, of December 21, 2026 with an interest rate of 4.12% and 2.91% at December 31, 2022 and 2021, respectively. The revolving and term loans under the Amended Credit Agreement bear interest at the BSBY Margin or Base Rate Margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement).
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 $6.0 million. 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, (e) any extraordinary, unusual, or non-recurring cash expenses and/or losses not exceeding $500,000 in the aggregate to the extent not included in the determination of operating income on MEH’s consolidated statements of profits and loss, (f) subject to
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Comerica’s approval, which may be granted or withheld in its reasonable credit judgment, any extraordinary, unusual, or non-recurring cash expenses or losses to the extent not included in the determination of operating income on MEH’s consolidated statements of profits and losses exceeding $500,000 in the aggregate, (g) any extraordinary, unusual, or non-recurring non-cash expenses and/or losses not included in the determination of operating income on MEH’s consolidated statements of profits and loss, and (h) any extraordinary, unusual, or non-recurring non-cash expenses and/or losses included in the determination of operating income on MEH’s consolidated statements of profits and loss, plus, to the extent not included in the calculation of net income, the
amount of dividends and distributions paid by the Excluded Entities (as defined in the Amended Credit Agreement) to MEH during such period minus the sum of (j) any non-cash unrealized derivative income during such period, (k) any extraordinary, unusual or non-recurring cash or non-cash income and/or gains not included in the determination of operating income on MEH’s consolidated statements of profits and loss, (l) any extraordinary, unusual, or non-recurring non-cash income and/or gains included in the determination of operating income on MEH’s consolidated statements of profits and loss, all as determined on a consolidated basis for MEH and its subsidiaries (excluding the Excluded Entities except where an Excluded Entity is specifically included in the calculation) in accordance with GAAP.
Under the Amended Credit Agreement, we are required to maintain the following ratios:
| Column 1 | Column 2 | Column 3 | Column 4 |
|---|---|---|---|
| • | a Total Leverage Ratio (as defined in the Amended Credit Agreement) of not more than 3.50 to 1.00 as of the end of any fiscal quarter from December 31, 2021 through June 29, 2023, 3.25 to 1.00 as of the end of any fiscal quarter from June 30, 2023 through June 29, 2024, and 3.00 to 1.00 as of the end of any fiscal quarter from June 30, 2024 and thereafter.; and |
| Column 1 | Column 2 | Column 3 | Column 4 |
|---|---|---|---|
| • | 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 December 31, 2022, we were in compliance with all financial covenants related to the Amended Credit Agreement.
The Amended Credit Agreement replaced our prior credit agreements with Comerica Bank 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 the sections entitled “Description of Indebtedness and Note 13—Debt to our audited 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 used the proceeds from our 2021 IPO to fund the Montauk Ag Renewables Asset Acquisition and the continued development of Montauk Ag Renewables. In 2023, we expect the development of Montauk Ag Renewables to be funded from our working capital, cash flow from operations and debt financing. We expect our non-development 2023 capital expenditures to range between $15,000 and $18,000. Our 2023 capital plans include annual preventative maintenance expenditures, annual wellfield expansion projects, critical spare expenditures, and other specific facility improvements. Additionally, we currently estimate that our existing 2023 development capital expenditures will range between $70,000 and $100,000. The majority of our 2023 development capital expenditures are related to our Pico digestion capacity increase, the ongoing development of Montauk Ag Renewables and the second Apex facility. Our Amended Credit Agreement provides us with an $120,000 revolving credit facility, with a $75,000 accordion option, providing us with access to additional capital to implement our acquisition and development strategy. We are currently in various stages of discussions regarding a variety of development and strategic growth opportunities. Development opportunities include: up to seven LFG RNG sites which we could contemplate generating renewable electricity to qualify for eRINs and up to two waste water treatment RNG opportunities. If we ultimately enter into definitive agreements for any of these opportunities, we expect to incur material capital expenditures related to either acquisitions costs or development costs, or both. As we continue to explore
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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.
Cash Flow
The following table presents information regarding our cash flows and cash equivalents for years ended December 31, 2022 and 2021:
| Year Ended December 31, | ||||||||
|---|---|---|---|---|---|---|---|---|
| 2022 | 2021 | |||||||
| Net cash flows provided by operating activities | $ | 81,066 | $ | 42,879 | ||||
| Net cash flows used in investing activities | (20,794 | ) | (19,474 | ) | ||||
| Net cash flows (used in) provided by financing activities | (8,279 | ) | 8,649 | |||||
| Net increase in cash and cash equivalents | 51,993 | 32,054 | ||||||
| Restricted cash, end of period | 429 | 347 | ||||||
| Cash and cash equivalents and restricted, end of period | 105,606 | 53,613 |
For the year ended December 31, 2022, we generated $81,066 of cash from operating activities, an 89.1% increase from the prior year ended December 31, 2021 of $42,879. For the year ended December 31, 2022, income and adjustments to income from operating activities provided $75,832 compared to $46,549 in 2021. Working capital and other assets and liabilities provided $5,234 in the current period compared to $3,671 being used in the prior year period. When we commission new sites, we invest capital to ramp up operations prior to the project generating revenue. Our net cash flows used in investing activities has historically focused on project development and facility maintenance.
Our net cash flows used in investing activities has historically focused on project development and facility maintenance. For 2022, our capital expenditures were $22,277, of which $6,860 and $3,555 were related to the Pico facility digestion capacity increase and Montauk Ag Renewables in North Carolina, respectively. For 2021, our capital expenditures were $9,986, of which approximately $2,428 were related to optimization projects at our recently commissioned facilities and $1,000 related to the Pico Feedstock Amendment. We acquired assets of $4,142, including $341 in acquisition costs for land, building, mobile equipment and other property, plant and equipment for the Montauk Ag Renewables Acquisition in North Carolina and we paid an additional $5,531, including $31 in acquisition costs, for land, land improvements and a building.
Our net cash flows used in financing activities of $8,279 for 2022 decreased by $16,928 compared to cash provided by in financing activities of $8,649 in 2021. In 2021, the closing of our IPO provided $15,593 in proceeds after payment of commissions and expenses. The company reacquired 950,214 shares with a value of approximately $10,813 connection with withholding shares from restricted stock awards pursuant to elections made by employees under Section 83(b) of the Code related to the IPO. Additionally, during 2021 and in connection with the Distribution, we loaned $8,940 to MNK for its dividends tax liability arising under the South African Income Tax Act, 1962, as amended. As security for this loan, MNK has pledged certain of its shares in the Company to Montauk Renewables and agreed to use the proceeds from the sale of such shares to repay this loan. During 2021, we borrowed $80,000 under our revolving credit agreement to be used primarily for development capital expenditures.
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
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GAAP. Our off-balance sheet arrangements are limited to the outstanding letters of credit and operating leases 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.
The Company has contractual obligations involving asset retirement obligations. See Note 9 in the Consolidated Financial Statements for further information regarding the asset retirement obligations.
The Company has contractual obligations under our debt agreement, including interested payments and principal repayments. See Note 13 in the Consolidated Financial Statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. During 2022, we had $3,905 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 usage against these outstanding letters of credit. During 2021, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $3,905.
The Company has contractual obligations involving operating leases. See Note 19 in the Consolidated Financial Statements for further information related to the lease obligations. In 2022, the Company entered into a new, ten year corporate office lease with monthly rent payments of approximately $43 per month beginning in 2023, the first full year of the lease. The lease includes annual rent increases. Also, in 2022, the Company entered into a four year extension for its regional corporate office with monthly rent payments of approximately $5 per month beginning in 2023. The lease includes annual rent increases.
The Company has other contractual obligations associated with our fuel supply agreements. The expiration of these agreements range between 5-21 years. agreements range. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,385.