Montauk Renewables, Inc. (MNTK) FY 2021 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
Montauk Ag Asset Acquisition
On May 10, 2021, the Company, through a newly formed wholly-owned subsidiary Montauk Ag, completed a series of transactions with Joseph P. Carroll, Jr. (“Carroll”), Martin A. Redeker (“Redeker”) and certain of their affiliates to purchase identified assets 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.
The purchase price, excluding acquisition costs, for the Montauk Ag Renewables Acquisition consisted of (i) $3,801 paid in cash on May 10, 2021 (minus certain costs and indebtedness) and (ii) two restricted stock awards, in equal amounts, granted under the MRI EICP, with an aggregate value not to exceed $12,500, awarded
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to each of Messrs. Carroll and Redeker in connection with their respective employment with the Company following the closing of the Montauk Ag Renewables Acquisition (the “RS Awards”). For more information about the RS Awards, see Note 15 to our audited consolidated financial statements.
During the third quarter of 2021, we continued to execute on our plans for the Montauk Ag Renewables Acquisition. In August 2021, we were granted a patent over 24 specific aspects of continuous-feed, closed-loop reactor technology acquired in the acquisition. We believe that the reactor enables
near-zero-emissions
conversion of agricultural waste into multiple
non-fossil,
renewable-fuel alternatives, is capable of producing multiple units of renewable energy for each unit of conventional energy consumed and is capable of sequestering multiple tons of greenhouse gas equivalent emissions (CO2e) for every ton emitted. We expect the reactor, with certain enhancements, to better address some of the environmental challenges of industrial agriculture, including lagoon capacity constraints, watershed contamination, odor issues, nutrient abundances and containment and
disposal of animal waste, regardless of location or size. The reactor is operational and while we continue to make improvements to the reactor to optimize its functionality, we do not currently expect this facility to be commissioned with these improvements during 2022.
In the fourth quarter of 2021, we also closed on a $5,447 transaction to acquire approximately 146 acres and an existing approximately 500,000 square foot structure which we plan to use as we expand the production processes purchased in the Montauk Ag Renewables Acquisition. We have also executed master services agreements that provides access to waste feedstock biogas production. The feedstock will be sourced from swine waste located at our farming partner locations. We do not currently expect the revenues from these agreements to be material.
We are at the beginning stages of developing the opportunities associated with Montauk Ag 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 Montauk Ag production. We do not currently expect significant production to commence during 2022 related to the current development timeline. As we commission and increase our production capabilities, we intend to add farms to this agreement as feedstock sources, which has the potential to secure more feedstock for our facility.
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 paid $1,000 in cash at the time of closing the amendment.
During the third quarter of 2021, and as part of our overall capacity expansion at the Pico facility, we undertook significant efforts to improve the performance of the existing digestion process at our Pico facility. We have temporarily idled RNG production at this facility in order to clean out settled solids in the digester, replace the cover of the digester, and make various other efficiency improvements. We incurred nonrecurring expenses of approximately $1,100 related to this project in addition to the $288 in asset disposal recognized during the third quarter of 2021 and approximately $325 in expected capital costs related to this project.
After the improvements were completed, production volumes have more than doubled in first quarter of 2022. As of December 31, 2021, we recorded an increase to the Pico
earn-out
liability of approximately $801 within royalties, transportation, gathering and production fuel based on our current estimate of expectations under this obligation. The improvement project has impacted the timeline for modeling Pico’s initial CI Score pathway model and subsequent auditing approval by CARB. We did not receive a temporary CI pathway in 2021 and were not able to generate LCFS credit revenue on 2021 production. We will be storing 2022 production while CARB completes its CI Score Pathway. We expect to receive the results of this approval during the second half of 2022. However, we do not currently expect to receive LCFS credit revenue on 2022 production until 2023.
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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 correlates. |
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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 |
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| 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. On December 7, 2021, the EPA issued a proposed rule modifying the RVOs for 2020 and setting the RVOs for 2021 and 2022. In addition, the proposed rule included the addition of a supplemental volume of renewable fuel in 2022 to address the United States Court of Appeals for the D.C. Circuit’s 2017 remand of the 2013-2016 standards and laid out a proposed regulatory framework to allow biointermediates to be included in the program. The manner in which the EPA will establish RVOs beginning in 2023, when the statutory RVO mandates are set to expire, is expected to create additional uncertainty as to RIN pricing. Further changes to the CI score assigned to a project upon its renewal or a change in the way CARB develops the CI score for a new project 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 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 and counterparty sharing agreements, which provide floor prices in excess of commodity indices and sharing percentages of the monetization of Environmental Attributes. Under these sharing arrangements, we receive a portion of the profits derived from counterparty monetization of the Environmental Attributes in excess of the floor prices. These arrangements are currently set to expire during 2022 and we are in negotiations to replace these arrangements. |
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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.
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. In November 2019, our McCarty facility lost production capacity of one of its engines due to its failure. Production was not restored until March 2020 when a replacement was commissioned. We recorded $3.9 million as a gain on insurance proceeds related to the replacement of property and business interruption. 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.
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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 subsequently 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 expect lower than historical volumes through 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 do not currently expect to receive LCFS credit revenue on 2022 production until 2023. |
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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. |
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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 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 2022 RIN generation and our current 2022 RIN commitments are at an average D3 RIN price of approximately $3.40 with commitments through June 2022. 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. We expect increased general and administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2022. 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. 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, | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | Change | Change% | |||||||||||||
| Revenues | ||||||||||||||||
| Renewable Natural Gas Total Revenues | $ | 131,803 | $ | 83,236 | $ | 48,567 | 58.3 | % | ||||||||
| Renewable Electricity Generation Total Revenues | $ | 15,449 | $ | 16,665 | $ | (1,216 | ) | (7.3 | )% | |||||||
| RNG Metrics | ||||||||||||||||
| CY RNG production volumes (MMBtu) | 5,688 | 5,746 | (58 | ) | (1.0 | )% | ||||||||||
| Less: Current period RNG volumes under fixed/floor-price contracts | (1,596 | ) | (2,009 | ) | 413 | (20.5 | )% | |||||||||
| Plus: Prior period RNG volumes dispensed in current period | 353 | 266 | 87 | 32.7 | % | |||||||||||
| Less: Current period RNG production volumes not dispensed | (372 | ) | (353 | ) | (19 | ) | 5.4 | % | ||||||||
| Total RNG volumes available for RIN generation(1) | 4,073 | 3,650 | 423 | 11.6 | % | |||||||||||
| RIN Metrics | ||||||||||||||||
| Current RIN generation ( x 11.727)(2) | 47,758 | 42,809 | 4,949 | 11.8 | % | |||||||||||
| Less: Counterparty share (RINs) | (5,124 | ) | (4,701 | ) | (423 | ) | 9.0 | % | ||||||||
| Plus: Prior period RINs carried into CY | 110 | 1,330 | (1,220 | ) | (91.7 | )% | ||||||||||
| Less: CY RINs carried into next CY | (140 | ) | (99 | ) | (41 | ) | 41.4 | % | ||||||||
| Total RINs available for sale(3) | 42,604 | 39,339 | 3,265 | 8.3 | % | |||||||||||
| Less: RINs sold | (42,604 | ) | (39,335 | ) | (3,269 | ) | 8.3 | % | ||||||||
| RIN Inventory | 0 | 3 | (3 | ) | (100.0 | )% | ||||||||||
| RNG Inventory (volumes not dispensed for RINs)(4) | 372 | 352 | 20 | 5.7 | % | |||||||||||
| Average Realized RIN price | $ | 1.91 | $ | 1.31 | $ | 0.60 | 45.8 | % | ||||||||
| Operating Expenses | ||||||||||||||||
| Renewable Natural Gas Operating Expenses | $ | 65,046 | $ | 50,092 | $ | 14,954 | 29.9 | % | ||||||||
| Operating Expenses per MMBtu (actual) | $ | 11.44 | $ | 8.72 | $ | 2.72 | 31.2 | % | ||||||||
| Renewable Electricity Generation Operating Expenses | $ | 12,177 | $ | 11,555 | $ | 622 | 5.4 | % | ||||||||
| $/MWh (actual) | $ | 66.56 | $ | 62.13 | $ | 4.43 | 7.1 | % | ||||||||
| Other Metrics | ||||||||||||||||
| Renewable Electricity Generation Volumes Produced (MWh) | 183 | 186 | (3 | ) | (1.6 | )% | ||||||||||
| Average Realized Price $/MWh (actual) | $ | 84.45 | $ | 89.60 | $ | (5.15 | ) | (5.7 | )% |
| Column 1 | Column 2 |
|---|---|
| (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. |
| Column 1 | Column 2 |
|---|---|
| (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, 2021 and 2020
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, | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | Change | Change% | |||||||||||||
| Total operating revenues | $ | 148,127 | $ | 100,383 | $ | 47,744 | 47.5 | % | ||||||||
| Operating Expenses: | ||||||||||||||||
| Operating and maintenance expenses | 49,477 | 43,463 | 6,014 | 13.8 | % | |||||||||||
| General and administrative expenses | 42,552 | 16,594 | 25,958 | 156.4 | % | |||||||||||
| Royalties, transportation, gathering and production fuel | 28,683 | 18,284 | 10,399 | 56.9 | % | |||||||||||
| Depreciation and amortization | 22,869 | 22,117 | 752 | 3.4 | % | |||||||||||
| Gain on insurance proceeds | (332 | ) | (3,934 | ) | 3,602 | (91.6 | )% | |||||||||
| Impairment loss | 1,191 | 278 | 913 | 328.4 | % | |||||||||||
| Transaction costs | 352 | — | 352 | 0 | % | |||||||||||
| Total operating expenses | $ | 144,792 | $ | 96,802 | $ | 47,990 | 49.6 | % | ||||||||
| Operating profit | $ | 3,335 | $ | 3,581 | $ | (246 | ) | (6.9 | )% | |||||||
| Other expenses: | 3,702 | 4,974 | (1,272 | ) | (25.6 | )% | ||||||||||
| Income tax expense (benefit) | 4,161 | (5,996 | ) | 10,157 | (169.4 | )% | ||||||||||
| Net (loss) income | $ | (4,528 | ) | $ | 4,603 | $ | (9,131 | ) | (198.4 | )% |
Revenues for the Years Ended December 31, 2021 and 2020
Total revenues in 2021 were $148,127, an increase of $47,744 (47.5%) compared to $100,383 million in 2020. The primary driver for this increase relates to an increase of 45.5% in realized RIN pricing during 2021 of $1.91 compared to $1.31 in 2020. Additionally an increase in natural gas index pricing of 46.0% in 2021 of $3.84 compared to $2.63 in 2020. We also recognized higher revenues under our counterparty sharing agreements of $7,981 in 2021 compared to 2020, primarily related to increased RIN index prices.
Renewable Natural Gas Revenues
We produced 5,688 MMBtu of RNG during 2021, a decrease of 58 MMBtu (1.0%) from the 5,746 MMBtus produced in 2020. Of the decrease in 2021 volumes, 94 MMBtus were produced from development sites commissioned during 2020. Our McCarty site produced 210 MMBtu less in 2021 compared to 2020 as a result of the collection system being hampered by increased volumes of water and process equipment failures.
Revenues from the Renewable Natural Gas segment in 2021 were $131,803, an increase of $48,567 (58.3%) compared to $83,236 in 2020. Average commodity pricing for natural gas for 2021 was 46.0% higher than the prior year. During 2021, we self-marketed 42,604 RINs, representing a 3,269 increase (8.3%) compared to 39,335 in 2020. 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 2021 was $1.91 as compared to $1.31 in 2020, an increase of 45.8%. This compares to the average D3 RIN index price for 2021 of $3.02 being approximately 102.7% higher than the average D3 RIN index price in 2020. All our RIN sales in 2021 and 2020 were priced generally on the D3 index with none based on CWC. At December 31, 2021, we had approximately 0.4 million MMBtus available for RIN generation and had approximately 0.1 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, 2020.
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Renewable Electricity Generation Revenues
We produced 183 MWh in Renewable Electricity in 2021, a decrease of approximately 3 MWh (1.6%) compared to 186 MWh in 2020. In 2021, our Bowerman facility produced 152 MWh, an increase of 8 MWh (5.3%) over the 144 MWh produced in 2020. The increase is primarily driven by the California wildfires that forced the facility to temporarily shut down in October 2020. Offsetting this increase is our Security facility that had zero production in 2021 compared to 8 MWh in 2020, due to ongoing projects to restore the engines at our Security facility.
Revenues from Renewable Electricity facilities in 2021 were $15,449, a decrease of $1,216 (7.3%) compared to $16,665 in 2020. Prior to reporting Pico in RNG, Pico accounted for $707 of the decrease between 2021 and 2020. Our Security facility contributed to $442 of the decrease as a result of having zero production in 2021.
For 2021, 100.0% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with the underlying PPAs, as compared to 100.0% in 2020. This provides the Company with certainty of revenues resulting from our Renewable Electricity sites.
Corporate Analysis
While we did not have any gas hedge programs in 2021, our gas hedge program during 2020 was priced at rates in excess of the actual index price, resulting in a loss of $388. During 2021, we recorded revenues of $875 related to RINs purchased in 2021. 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 2020.
Expenses for the Years Ended December 31, 2021 and 2020
General and Administrative Expenses
Total general and administrative expenses of $42,552 in 2021, an increase of $25,958 (156.4%) compared to $16,594 in 2020. Of the total expense in 2021, $22,421 is related to stock-based compensation expense. Excluding the impacts of stock-based compensation, general and administrative expenses increased approximately $3,336. Employee related costs, including stock-based compensation, increased approximately $21,286 (242.7%) in 2021 as compared to 2020. Additionally, our corporate insurance premiums increased approximately $2,893 (110.3%) during 2021 over 2020 period primarily related to premium increases associated with the completion of the IPO. Professional fees increased approximately $1,392 (46.8%) during 2021, primarily resulting from our successful completion of the IPO and Reorganization Transactions and ongoing costs of being a public company.
Renewable Natural Gas Expenses
Operating and maintenance expenses for our RNG facilities in 2021 were $38,114, an increase of $4,563 (13.6%) compared to $33,551 in 2020. Approximately $4,662 of the increase related to development sites commissioned during 2020. Exclusive of the effects of these development sites, operating and maintenance expenses for 2021 were $33,542, a decrease of $99 (0.3%) compared to $33,551 in 2020. In the first quarter of 2021, our Houston, TX facilities were favorably impacted by lower utility rates as a result of a weather event. Certain of our utility contracts have provisions that when we are not using utilities, the providers are able to contribute that capacity back into the market and we receive credit against our future bills. The 2021 weather event, which temporarily impacted our Texas facilities utility consumption resulted in our RNG utilities being approximately $470 lower for 2021 as compared to 2020.
Royalties, transportation, gathering and production fuel expenses for the Company’s RNG facilities for 2021 were $26,932, an increase of $10,391 (62.8%) compared to $16,541 in 2020. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 20.4% for 2021 from 19.9% in 2020.
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Approximately $1,286 of the increase relates to development sites commissioned during 2020. Exclusive of the effects of the development sites, royalty related costs for 2021 were $25,646, an increase of $9,105 (55.0%) compared to $16,541 in 2020.
Renewable Electricity Expenses
Operating and maintenance expenses for our Renewable Electricity facilities in 2021 were $10,426, an increase of $614 (6.3%) compared to $9,812 in 2020. We reported the results of Pico within the Renewable Electricity Generation segment until October 2020. Of the total, Pico contributed $1,389 in 2020 and, exclusive of Pico, Renewable Electricity facility operating and maintenance expenses increased by $2,002 (19.2%). The increase is primarily driven by the timing of scheduled engine preventative maintenance intervals at our Bowerman facility, of approximately $2,765 higher in 2021 over 2020. Offsetting this increase is a true up of closure reserves related to Atascocita and Coastal Plains Electric facilities which have since been converted to RNG facilities, which was approximately $554.
Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for 2021 were $1,751, an increase of $8 (0.5%) compared to $1,743 in 2020 and as a percentage of Renewable Electricity Generation segment, revenues increased from 10.5% to 11.3%.
Royalty Payments
Royalties, transportation, gathering, and production fuel expenses in 2021 were $28,683, an increase of 10,399 (56.9%) compared to $18,284 in 2020. 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 2021 were $22,869, an increase of $752 (3.4%) compared to $22,117 in 2020. Of the increase, $1,612 relates to development sites commissioned during 2020.
Impairment loss
We calculated and recorded impairment losses of $1,191 for 2021, an increase of $913 (328.4%) compared to $278 for 2020. The primary driver of this increase relates to an impairment of $626 due to landfill host requesting us to decommission a previously converted electric to RNG site. Additionally, we recorded an impairment of $421 related to disposal of machinery at our Rumpke facility.
Other Expenses (Income)
Other expenses in 2021 were $3,702, a decrease of $1,272 (25.6%) compared to $4,974 in 2020. Reduced interest expense of $1,411 in 2021 compared to 2020 associated primarily with lower debt balances through 2021 before amending our credit agreement during the fourth quarter of 2021.
Income Tax Expense (Benefit)
Prior to 2018, we generated sizeable NOLs, which reduced our income tax payable for
2019. In 2020 we generated additional NOLs which can be carried forward indefinitely. In 2021, we expect to utilize NOL carryforwards. Based upon our historical
pre-tax
book income and forecasts, we expect to utilize all remaining NOLs and thus have not recorded a valuation allowance against such NOLs.
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Our effective income tax rate (“
ETR
”) for 2021 was an expense of 1,132.13% compared to benefit of 430.04% for the prior year period. This increased expense in the ETR is driven by low
pre-tax
loss compared to the tax expense of $4,161 for 2021. Tax expense is driven by $4,382 of permanent disallowance of officers compensation under Section 162(m) of the Code.
The CARES Act and the Consolidated Appropriations Act, enacted by the United States on March 27, 2020 and December 27, 2020, respectively, did not have a material impact on our provision for income taxes for the year ended December 31, 2020 or December 31, 2021. 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 this legislation.
Operating Profit for the Years Ended December 31, 2021 and 2020
Operating profit in 2021 was $3,335, a decrease of $246 (6.9%) compared to $3,581 in 2020. RNG operating profit for 2021 was $50,350, an increase of $28,124 (126.5%) compared to $22,226 in 2020. Renewable Electricity Generation operating loss for 2021 was $3,090, a decrease of $810 (35.5%) compared to $2,280 in 2020.
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, | ||||||||
|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | |||||||
| Net (loss) income | $ | (4,528 | ) | $ | 4,603 | |||
| Depreciation and amortization | 22,869 | 22,117 | ||||||
| Interest expense | 2,928 | 4,339 | ||||||
| Income tax expense (benefit) | 4,161 | (5,996 | ) | |||||
| Consolidated EBITDA | 25,430 | 25,063 | ||||||
| Impairment loss(1) | 1,191 | 278 | ||||||
| Transaction costs | 352 | — | ||||||
| Loss on extinguishment of debt | 154 | — | ||||||
| Net loss on sale of assets | 822 | 320 | ||||||
| Non-cash hedging charges | — | 388 | ||||||
| Adjusted EBITDA | $ | 27,949 | $ | 26,049 |
| Column 1 | Column 2 |
|---|---|
| (1) | For the 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. For year ended December 31, 2020, we recorded an impairment of $278 termination of a development agreement related to our Pico project. |
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Liquidity and Capital Resources
Sources of Liquidity
At December 31, 2021 and 2020, our cash and cash equivalents, net of restricted cash, was $53,266 and $20,992, 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, 2021, we had debt before debt issuance costs of $80,000, compared to debt before debt issuance costs of $66,697 at December 31, 2020.
Our debt before issuance costs (in thousands) is as follows:
| December 31, 2021 | December 31, 2020 | ||||||
|---|---|---|---|---|---|---|---|
| Term Loans | $ | 80,000 | $ | 30,000 | |||
| Revolving Credit Facility | — | 36,697 | |||||
| Debt before debt issuance costs | $ | 80,000 | $ | 66,697 |
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, 2021, $80,000 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 and in quarterly installments of $3,000 through the maturity of December 21, 2026 with an interest rate of 2.91% and 2.96% at December 31, 2021 and 2020, 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 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
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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, 2021, 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 expect our non-development 2022 capital expenditures to range between $10,000 and $12,000. Our 2022 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 2022 development capital expenditures will range between $25,000 and $30,000. 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.
Cash Flow
The following table presents information regarding our cash flows and cash equivalents for years ended December 31, 2021 and 2020:
| Year Ended December 31, | ||||||||
|---|---|---|---|---|---|---|---|---|
| 2021 | 2020 | |||||||
| Net cash flows provided by operating activities | $ | 42,879 | $ | 28,684 | ||||
| Net cash flows used in investing activities | (19,474 | ) | (15,987 | ) | ||||
| Net cash flows provided by (used in) financing activities | 8,649 | (1,500 | ) | |||||
| Net increase in cash and cash equivalents | 32,054 | 11,197 | ||||||
| Restricted cash, end of period | 347 | 567 | ||||||
| Cash and cash equivalents and restricted, end of period | 53,613 | 21,559 |
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For the year ended December 31, 2021, we generated $42,879 million of cash from operating activities, a 49.5% increase from the prior year ended December 31, 2020 of $28,684. For the year ended December 31, 2021, income and adjustments to income from operating activities provided $46,549 compared to $22,537 in 2020. Working capital and other assets and liabilities used $3,671 in the current period compared to $6,145 on being provided 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.
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, we paid an additional $5,531, including $31 in acquisition costs, for land, land improvements and a building. For 2020, our capital expenditures were $17,646, $927, $5,860, and $2,013 relate to the construction of our Galveston, Coastal Plains, and Pico RNG facilities, respectively. We also incurred $3.5 million in capital expenditures rebuilding the failed engine at our McCarty RNG site.
Our net cash flows used in financing activities of $8,649 for 2021 increased by $10,149 compared to 2020. In 2021, the closing of our IPO provided $15,593 in proceeds after payment of commissions and expenses. The company reacquired 950,214 shared with a value of approximately $10,813 connection with withholding shares from restricted stock awards pursuant to elections make 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 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 2021, 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 2020, we did not have
off-balance
sheet arrangements other than outstanding letters of credit of approximately $7,145.
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.
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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 $7 to $1,380.