Exhibit 99.5
Management’s
Discussion and Analysis of Financial Condition
and Results of Operations OF ARIA
The following discussion of our financial condition and results of operations should be read in conjunction with the financial statements and related notes included in the proxy statement on Schedule 14A filed with the SEC on August 12, 2021 (the “Proxy Statement”) and in this Form 8-K. Certain information included in this discussion contains forward-looking statements that involve numerous risks and uncertainties. Our actual results may differ materially from those projected or implied by the forward-looking statements. Forward-looking statements are based on current expectations and assumptions and currently available data and are neither predictions nor guarantees of future events or performance. You should not place undue reliance on forward-looking statements, which speak only as of the date hereof. See “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” for a discussion of factors that could cause our actual results to differ from those expressed or implied by forward-looking statements.
Unless the context otherwise requires, all references in this section to “Aria,” “we,” “us,” or “our” refer to the business of Aria Energy LLC and its subsidiaries prior to the consummation of the Business Combination. Unless the context otherwise requires, all references in this section to the “Combined Company” refer to Archaea Energy Inc. and its subsidiaries following the consummation of the Business Combination. All dollar figures used herein are in thousands, unless the context suggests otherwise.
Overview
We are a growth-oriented energy company focused on owning, operating and developing long-life energy projects that deliver stable, long-term cash flows. We believe our business strategy will allow us to achieve sustainable future growth in our cash flows. Today we own and operate a core business comprised of low-marginal-cost renewable energy projects that generate baseload electricity or deliver pipeline-quality RNG to our customers. We are one of the premier LFG companies in the United States, with 25 owned and/or operated LFG projects in 13 states. Our portfolio consists of 9 RNG projects with a total daily capacity of 24,880 MMBtu and 16 projects generating baseload renewable electricity with a total capacity to produce 115.7 MW of power. Included among our electric projects are four plants operating for third parties, amounting to 22.4 MW of capacity. All of our projects are low-cost, environmentally friendly and benefit from state-mandated RPS, federal environmental compliance requirements for landfill owners and growing waste management demands that are highly correlated to the recent economic recovery. The LFG industry in the United States is highly fragmented and we believe that the Combined Company will be well positioned to take advantage of acquisition opportunities following the consummation of the Business Combination. Our projects utilize established technology and we believe that our business is highly scalable. A significant majority of our owned projects operate under long-term off-take agreements with investment grade and other creditworthy counterparties that have a weighted average remaining life (based on design capacity) of approximately ten years for RNG projects and five years for power projects as of June 30, 2021. Our remaining projects benefit from market pricing in attractive power and RNG markets.
We are a market leader and one of the largest companies in the LFG sector in North America. We have demonstrated a strong ability to grow our business through both development and acquisitions. We have developed or constructed nine projects (six RNG and three Power) over the last seven years and we have successfully integrated two acquisitions since 2015. As we grow our company in the future, we will continue to focus on high-quality, long-life projects with creditworthy counterparties that will enable us to support our growth strategy.
The Business Combination
On April 7, 2021, we entered into the Aria Merger Agreement with RAC Buyer, Company Merger Sub, RAC Intermediate, Rice Opco, the Aria Equityholder Representative and RAC, a copy of which is attached to the Proxy Statement as Annex A.
Additionally, on April 7, 2021, RAC also entered into the Archaea Merger Agreement with (i) RAC Opco, (ii) RAC Intermediate, (iii) RAC Buyer, (iv) Archaea Merger Sub, (v) Archaea Seller, and (vi) Archaea Energy II, a copy of which is attached to the Proxy Statement as Annex B.
Pursuant to the Aria Merger Agreement, the aggregate merger consideration payable upon closing of the Aria Merger to Aria Holders is expected to be approximately $680.0 million, subject to certain adjustments set forth in the Aria Merger Agreement for, among other things, Aria’s cash, indebtedness, unpaid transaction expenses and certain capital expenditures. The merger consideration will consist of both cash consideration and consideration in the form of newly issued Class A units of RAC Opco and newly issued shares of Class B Common Stock. The cash component of the consideration will be an amount equal to $450.0 million, subject to certain adjustments set forth in the Aria Merger Agreement. The remainder of the consideration will consist of 23.0 million Class A units of RAC Opco and 23.0 million shares of Class B Common Stock.
Following the Closing, RAC will retain its “up-C” structure, whereby all of the equity interests in Aria and Archaea will be held by RAC Buyer, all of the equity interests in RAC Buyer will be held by RAC Intermediate, all of the equity interests in RAC Intermediate will be held by RAC Opco and RAC’s only assets will be its equity interests in RAC Opco. Following the Closing, RAC will be renamed Archaea Energy Inc.
In accordance with ASC 810, RAC Opco is considered a VIE where RAC is the sole managing member of RAC Opco, and therefore, the primary beneficiary. As such, RAC consolidates RAC Opco, and the unitholders that hold economic interest directly at RAC Opco would be presented as noncontrolling interest in both the pro forma balance sheet and income statement. Archaea is considered the accounting acquirer of the Business Combinations based on ASC 805 because Archaea Holders will have the largest portion of the voting power of the Combined Company, Archaea’s senior management will comprise the majority of the senior management of the Combined Company, and the Archaea Holders, will appoint the majority of board members exclusive of the independent board members. The Archaea Merger represents a reverse merger and will be accounted for as a reverse recapitalization in accordance with GAAP. Under this method of accounting, RAC will be treated as the “acquired” company for financial reporting purposes. Accordingly, for accounting purposes, the Archaea Merger will be treated as the equivalent of Archaea issuing shares for the net assets of RAC, accompanied by a recapitalization. The net assets of RAC will be stated at historical cost. No goodwill or other intangible assets will be recorded. The Aria Merger represents an acquisition of a business and Aria’s identifiable assets acquired, liabilities assumed and any non-controlling interests will be measured at their acquisition date fair value.
As a result of the Business Combinations, the Combined Company will become a publicly traded company with its common stock trading on the New York Stock Exchange, which will require it to hire additional personnel and implement procedures and processes to address public company regulatory requirements and customary practices. The Combined Company expects to incur material additional annual expenses as a public company for, among other things, directors’ and officers’ liability insurance, director fees, and additional internal and external accounting, legal, and administrative resources, including increased personnel costs, audit and other professional service fees.
Impact of COVID-19
The impact of the COVID-19 pandemic and measures to prevent its spread have been impactful and continue to affect our business in several ways. In March 2020, Aria implemented a COVID-19 response team, led by senior management, which initially met on a daily basis to report health status and develop guidelines to protect our workforce. Daily health monitoring and internal contact tracing protocols were implemented. The response team sought feedback from employees, particularly those working in our plants, in developing policies and protocols. Work-from-home protocols were implemented immediately where possible for non-operations personnel. For on-site employees, PPE was provided and enhanced hygiene and physical distancing protocols were implemented. The necessary IT improvements were initiated to facilitate a remote work environment, and we leveraged supplier networks to source COVID-19 specific PPE. Communications from senior leadership to all employees were enhanced, with weekly updates provided. To date, Aria has not experienced any spread of the disease within its operating and management locations or any material interruptions to its business operations. As of the date of the Proxy Statement, such business changes and additional costs have not been, individually or in the aggregate, material to Aria.
Recently, several vaccines have been authorized for use against COVID-19 in the United States and internationally. As a result of distribution of the vaccines, various federal, state and local government have begun to ease the movement restrictions and initiatives while continuing to adhere to enhanced safety measures, such as physical distancing and face mask protocols. However, the uncertainty continues to exist regarding the severity and duration of the pandemic, the speed and effectiveness of vaccine and treatment developments and deployment, potential mutations of COVID-19, and the effect of actions taken and that will be taken to contain COVID-19 or treat its effect, among others.
2
We remain uncertain of the ultimate effect COVID-19 could have on our business notwithstanding the distribution of several U.S. government approved vaccines and various federal, state and local governments having begun to ease the movement restrictions and public health initiatives while continuing to adhere to enhanced safety measures, such as physical distancing and face mask protocols. This uncertainty as to the duration and severity of economic effects from the COVID-19 pandemic stems from the potential for, among other things, (i) continued rates of reported cases of COVID-19 and the potential for mutations of COVID-19 to result in increased rates of reported cases for which currently approved vaccines are not effective, (ii) unexpected disruptions to our operating projects and (iii) changes to customer demands.
LESPH Sale
Aria’s previously wholly-owned subsidiary, LES Project Holdings, LLC (“LESPH”), was a borrower under a term loan secured by the assets of LESPH and its subsidiaries, which matured on October 7, 2020, and under which LESPH was in default.
On June 1, 2020, Aria entered into a Sale Support and Cooperation Agreement with the Lender Parties (as defined therein) holding the LESPH debt, pursuant to which Aria agreed to engage in a sale process of LESPH. In connection therewith, Aria and the Lender Parties also entered into a Mutual Release Agreement effective upon the earlier of (a) the closing of the sale or foreclosure of LESPH or (b) June 30, 2021.
The Lender Parties and their advisor began a sale process that culminated in the receipt of final bids, and the selection of the winning bidder, in December 2020. Aria met its obligations under the Sale Support and Cooperation Agreement and was compensated in accordance therewith.
On March 1, 2021, LES Manager LLC and Energy Power Investment Company, LLC entered into a Membership Interest Purchase Agreement (MIPA) pursuant to which Aria agreed to sell 100% of LESPH for a purchase price of $58.5 million, subject to certain post-closing adjustments. The transaction closed and the terms of the Mutual Release Agreement became effective on June 10, 2021. The Mutual Release Agreement released lender claims and discharged the obligations of LESPH under the term loan agreement. Aria believes the agreement represents a settlement of the matter pertaining to the term loan default.
Key Factors that Affect our Business
Our results of operations in the near-term, as well as our ability to grow our business and revenue over time, could be impacted by a number of factors, including those affecting our industry generally and those that could specifically affect our existing projects and our ability to grow our operations.
Trends Affecting our Industry
The number of LFG projects producing RNG has increased dramatically since 2014, coinciding with the qualification of LFG resources as a D3 RIN under the federal RFS. LFG is also considered to be a renewable resource in all states that encourage or mandate the use of renewable energy. We believe these factors will contribute to driving the future growth of the LFG industry. The demand for RNG has grown significantly over the past several years and is expected to continue to grow due to (i) regulatory-driven requirements at the Federal Level (under the RFS) and state level (under Utility Commission mandates), (ii) broad-based utility and corporate support for voluntary renewable energy or sustainability initiatives, and (iii) the public sector looking to diversify energy sources from fossil fuel based alternatives.
We believe that the key drivers for the long-term growth in the LFG industry include:
● | overall demand for energy; |
● | governmental incentives, including RINs, RECs and LCFS, which make investments in renewable energy more attractive compared to traditional sources; |
3
● | environmental and social factors supporting increasing levels of renewable energy sources; |
● | price volatility for other fuel sources used for electricity generation; |
● | voluntary and institutional renewable energy procurement; |
● | federal and state carbon reduction goals; and |
● | regulatory and policy framework and support. |
Our Outlook
Our current operations are somewhat insulated by the factors above as a significant majority of our owned projects operate under long-term off-take agreements with investment grade and other creditworthy counterparties that have a weighted average remaining life of approximately ten years for RNG projects and five years for power projects as of June 30, 2021.
Our near-term growth strategy will focus on achieving operating efficiencies at our existing sites and potential opportunities to expand operations at existing sites. Most of the landfills that we operate at continue to accept waste and therefore the available landfill gas at these sites is expected to increase over time. In addition to expansion opportunities at existing sites, our strategy is to develop ongoing relationships with the largest landfill owners to allow us to negotiate project terms and avoid engaging in the request for proposal processes. By focusing on the largest landfill companies, we have been given RNG projects when the existing electric project contracts have expired. This has given us access to the large landfill projects that had already been developed with electric projects. This strategy avoids the administrative cost of doing one off RFPs that are not repeatable. The relationship we have developed with the largest landfill companies positions us to build RNG projects on their landfills going forward. We also continue to identify and evaluate opportunities to acquire existing LFG projects.
Factors Affecting Our Operational Results
The primary factors that will affect our financial results are (i) the amount of energy production and price of energy sales by our owned projects, (ii) the timing of commencement of commercial operations at our projects under construction, expansion of existing projects, development of new projects and project acquisitions, (iii) continued improvements in efficiency at our operations, (iv) interest expense on our new debt facilities, and (v) expenses associated with becoming a public company.
Commercial Operations at Our Construction Projects, Expansions of Our Existing Projects, Development of New Projects and Project Acquisitions
We currently have one cluster of anaerobic digester based RNG projects under construction which we expect to commence commercial operations before March 31, 2022. We are pursuing additional development opportunities, including expansions of operations at existing facilities, acquisitions of gas rights to develop new projects and acquisitions of existing LFG projects. The process of permitting an LFG project typically takes anywhere from six to 18 months to complete, depending on the project’s location and recovery technology. LFG projects can generally be constructed quickly, in nine to 18 months following receipt of all requisite permits.
Energy Sales from Our Projects
Our energy related products revenues are primarily determined by the amount of electricity we generate and RNG we produce and the average realized price we receive for each commodity and environmental attribute. Electricity revenues include energy, capacity and RECs either sold separately or bundled under a single contract price. RNG revenues include natural gas, RINs, and for certain projects, LCFS credits. A significant majority of our owned projects operate under long-term off-take agreements with investment grade and other creditworthy counterparties, but are subject to variable market price. We also receive payments related to our capacity at certain of our power projects. In addition, the sales of renewable attributes associated with the production of renewable energy, including RECs and RINs, comprise a significant portion of our revenues. Sales of renewable attributes directly accounted for more than 43.8% 37.6% and 45.1% of our total revenue for the year ended December 31, 2020, 2019 and 2018, respectively, and 54.6% and 40.4% for the six months ended June 30, 2021 and June 30, 2020 respectively, with renewable attributes also being bundled with the energy sold under certain of our off-take agreements.
4
Project Operations
Our portfolio of owned and/or operated projects has a total production capacity of 115.7 MW and 24,880 MMBtu’s per day. Our ability to generate energy from our LFG projects in an efficient and cost-effective manner is impacted by our ability to maintain the operating capacity of our projects. Landfill gas is more reliable than other intermittent renewable energy resources in that it is continually generated throughout each day, which allows our projects to operate as baseload facilities. Our projects have stable operating histories and utilize proven technology. A vast majority of our power projects use Caterpillar engines that were designed specifically for landfill gas use. The modular nature of our power projects allows for easy expansion, overhaul, repair and replacement without disrupting remaining engines. Similarly, our RNG projects also use proven technologies and Aria has operated these projects for multiple years. Newly constructed projects use technologies similar to existing operating projects, creating a common platform on which to incorporate new facilities.
Debt Financing
As of June 30, 2021, we had variable rate long-term debt. This debt was repaid in connection with the closing of the Business Combinations.
Aria has a senior secured credit facility that includes a term loan B with a remaining balance of $138.0 million at June 30, 2021 and December 31, 2020, and a revolving credit facility with total borrowing capacity of $40.2 million at June 30, 2021 and December 31, 2020. As of June 30, 2021 and December 31, 2020, Aria had no amounts drawn on the revolver. As of June 30, 2021, $16.1 million in letters of credit outstanding, which reduced the amount available under the revolving credit facility to $24.1 million. The senior secured credit facility was repaid and terminated in connection with the Business Combinations.
As previously noted, Aria had a subsidiary level term loan at LESPH with an outstanding balance of $102.8 million, which matured on October 7, 2020 and under which LESPH was in default. The default under the term loan was remediated as part of the aforementioned Mutual Release Agreement, effective as of June 10, 2021.
Seasonality
Revenues generated from our power projects in the New York and New England markets, all of which sell electricity at market prices, are affected by warmer and colder weather, and therefore a portion of our quarterly operating results and cash flows are affected by pricing changes due to regional temperatures. Our energy production can also be affected during summer months, as very warm temperatures can dry out a landfill if the landfill owner is unable to keep the landfill covered, which in turn reduces the landfill gas generated at the site. The weather during colder months affects power pricing and revenues due to the direct effect of natural gas pricing in the northeastern United States and its effect on supply during these months. Most of the revenues from our remaining power projects and the significant majority of the revenues from our gas projects are not affected in the short-term by such seasonal variances in energy pricing because they primarily sell pursuant to long-term off-take agreements at fixed prices.
Key Metrics
We regularly review a number of operating metrics and financial measurements to evaluate our performance, measure our growth and make strategic decisions. In addition to traditional GAAP performance and liquidity measures, such as revenue, cost of revenue, net income and cash provided by operating activities, we also consider MW and MMBtu sold, average realized price and Adjusted EBITDA in evaluating our operating performance. Each of these metrics is discussed below.
MWh and MMBtus Sold and Average Realized Price
Power Sales — MWh Sold and Average Realized Electricity Price
For our power projects, the number of MWh sold and the average realized price per MWh sold are the operating metrics that determine the revenue that they generate. For any period presented, average realized electricity price represents total revenue from electricity sales divided by the aggregate number of MWh sold.
5
Gas Sales — MMBtu Sold and Average Realized Gas Price
For our gas projects, the number of MMBtu sold and the average realized price per MMBtu sold are the operating metrics that determine the revenue that they generate. For any period presented, average realized gas price represents total revenue from gas sales divided by the aggregate number of MMBtu sold.
Adjusted EBITDA
We define Adjusted EBITDA as net income before net interest expense, income taxes and depreciation, amortization and accretion and our share of net income or loss in non-consolidated joint ventures investments that are accounted for under the equity method, and excluding the effect of certain other items that we do not consider to be indicative of our ongoing operating performance such as mark-to-market adjustments and other non-recurring items. We also add back cash distribution received during the period from Aria’s nonconsolidated joint venture investments. In calculating Adjusted EBITDA, we also exclude mark-to-market adjustments to the value of our derivatives because we believe that it is useful for investors to understand, as a supplement to net income and other traditional measures of operating results, the results of our operations without regard to periodic, and sometimes material, fluctuations in the market value of such assets or liabilities. We also exclude impairment of assets, debt forbearance costs and costs related to sale of equity. Adjusted EBITDA is a non-U.S. GAAP measure. Adjusted EBITDA should be considered in addition to, and should not be considered superior to, or as a substitute for, the presentation of results determined in accordance with GAAP. We believe that Adjusted EBITDA and other non-GAAP financial measures assist management and investors when analyzing our performance by providing meaningful information that facilitates the comparability of underlying business results from period to period. We recognize there are limitations associated with the use of non-GAAP financial measures, including Adjusted EBITDA, as they may reduce comparability with other companies that use different methods to calculate similar non-GAAP measures. A further discussion of Adjusted EBITDA, including a reconciliation of Net income (loss), the most directly comparable GAAP measure, to Adjusted EBITDA is included below.
Components of Results of Operations
Revenue
Energy Revenue
A significant majority of our owned projects operate under long-term off-take agreements with investment grade and other creditworthy counterparties that have a weighted average remaining life (based on design capacity) of approximately five years for power projects and approximately ten years for RNG projects as of June 30, 2021. Power that is not covered by long-term off-take agreements is sold either under short-term bilateral agreements or in the wholesale markets. For electricity, these are markets organized and maintained by ISOs and RTOs (e.g., NYISO in New York, ISO-NE in New England and PJM Interconnection, L.L.C. (“PJM”) in the eastern United States). These ISOs and RTOs are well established organizations, regulated by states and FERC. For power sold in the wholesale markets, our company schedules the output in the day-ahead markets and receives the market price determined by the ISO or RTO through balancing the supply and demand for each day. In most cases we implement an optimization of the output sold in wholesale markets by using transmission to move the power into the ISO which offers better prices for RECs.
For RNG, we have contracts with long-term off-take agreements with creditworthy counterparties. Some contracts have fixed price offtake arrangements while the remaining sell natural gas and renewable attributes and are subject to market price changes.
We also generate revenue through the sale of renewable attributes. These attributes include RECs created from the production of renewable electricity, RINs and LCFS credits created from the sale of RNG as a transportation fuel. In most cases, RECs are sold to competitive energy suppliers or utilities to enable them to satisfy their statutory obligation to purchase renewable energy, while RINs are generally sold to energy companies, who in turn market to fuel refiners as renewable fuel credits to meet minimum percentage requirements for renewable volume obligations set by the EPA. RECs, RINs and LCFS credits are a stable source of revenue for our projects, offering visibility into near-term cash flows and also supporting cash flow stability going forward. We include revenues from the sale of these renewable attributes in energy related products revenue. REC revenue is recognized at the time power is produced where an active market and a sales agreement exists for the credits. RIN revenue is recognized when the fuel is produced or transferred to a third party.
6
Construction Revenue
Our construction revenue is derived from the installation of RNG plants owned by our nonconsolidated joint ventures. Aria recognizes revenue over time based on costs incurred and a fixed profit mark-up per construction agreement. Any intercompany profit is eliminated.
Cost of Revenue
Cost of Energy
Our cost of energy related products is comprised primarily of labor, parts and outside services required to operate and maintain equipment utilized in generating energy from our owned project facilities and from our landfill sources. Other costs directly related to the production of electricity and RNG are transportation costs associated with moving gas into pipelines, transmission costs of moving power between the ISOs, electricity consumed in the process of gas production, and royalty payments to landfill owners as stipulated in our gas rights agreements.
Cost of Construction
Cost of construction is comprised primarily of labor, equipment and other costs associated with our construction contract revenue incurred to date.
Depreciation, Amortization and Accretion
Depreciation expense is recognized using the straight-line method over the estimated useful lives of our assets. Accretion expense represents the increase in asset retirement obligations over the remaining operational life of the associated assets. Depreciation, amortization, and accretion includes the depreciation on our power and gas processing plants, amortization of intangible assets relating to our gas rights agreements, and debt financing costs, and the accretion of our asset retirement obligation.
General and Administrative Expenses
General and administrative expenses include our corporate offices and costs relating to labor, legal, accounting, treasury, information technology, insurance, communications, human resources, procurement, utilities, property taxes, permitting and other general costs.
Equity in Income of Joint Ventures
We hold interests in two joint ventures, one of which is LFGTE project, and other owns and operates four separate RNG facilities. Both partnerships are accounted for using the equity method. Equity in income of joint ventures includes earnings from projects located in Tennessee, Oklahoma, California and Michigan.
Interest Expense, Net
Interest expense is comprised of interest incurred under our variable rate financing arrangements.
Gain (Loss) on Swap Contracts
We used interest rate swaps and caps to manage the risk associated with interest rate cash flows on variable rate borrowings. We did not assess interest rate swaps for effectiveness. Changes in the fair values of interest rate swaps and realized losses were recognized as a component of interest expense. Our interest rate swaps were measured at fair value. The interest rate swaps were valued by discounting the net future cash flows using the forward LIBOR curve with the valuations adjusted by the counterparties’ credit default hedge rate.
7
Changes in the fair values of natural gas swap are recognized in gain (loss) on swaps and realized losses are recognized as a component of cost of energy expense. Valuation of the natural gas swap was calculated by discounting future net cash flows that were based on a forward price curve for natural gas over the life of the contract, with an adjustment for the counterparty’s credit default hedge rate.
Operating Segments
We are engaged in two reportable segments: one that operates a portfolio of renewable baseload electric generation assets and another that operates a portfolio of RNG production assets. We operate with two reportable segments based on a “management” approach, which designates the internal reporting used by management for making decisions and assessing performance as the source of the reportable segments. Management views and operates the business as two separate portfolios of assets. All of our projects and operations are located in the United States.
Results of Operations
Comparison of the Six Months Ended June 30, 2021 and 2020
The following table presents certain information relating to our operating results for the six months ended June 30, 2021 and June 30, 2020 (in thousands):
Six Months Ended June 30, | ||||||||||||||||
2021 | 2020 | $ Change | % Change | |||||||||||||
Revenue | ||||||||||||||||
Energy revenue | $ | 84,484 | $ | 62,649 | 21,835 | 34.9 | % | |||||||||
Construction revenue | 24 | 7,246 | (7,222 | ) | (99.7 | )% | ||||||||||
Amortization of intangibles and below-market contracts | (1,908 | ) | (1,834 | ) | (74 | ) | (4.0 | )% | ||||||||
Total revenue | 82,600 | 68,061 | 14,539 | 21.4 | % | |||||||||||
Cost of revenue | ||||||||||||||||
Cost of energy | 41,116 | 36,013 | (5,103 | ) | (14.2 | )% | ||||||||||
Cost of construction | 23 | 6,901 | 6,878 | 99.7 | % | |||||||||||
Depreciation, amortization and accretion | 11,314 | 15,580 | 4,266 | 27.4 | % | |||||||||||
Total cost of revenue | 52,453 | 58,494 | 6,041 | 10.3 | % | |||||||||||
Gross profit | 30,147 | 9,567 | 20,580 | 215.1 | % | |||||||||||
Gain on disposal of assets | (1,347 | ) | — | 1,347 | — | |||||||||||
General and administrative expenses | 13,063 | 9,631 | (3,432 | ) | (35.6 | )% | ||||||||||
Operating income (loss) | 18,431 | (64 | ) | 18,495 | NM | |||||||||||
Other income (expense) | ||||||||||||||||
Equity in income of joint ventures | 13,325 | 3,446 | 9,879 | 286.7 | % | |||||||||||
Interest expense, net | (8,676 | ) | (9,664 | ) | 988 | 10.2 | % | |||||||||
Gain (loss) on swap contracts | 556 | (322 | ) | 878 | NM | |||||||||||
Gain on extinguishment of debt | 61,411 | — | 61,411 | NM | ||||||||||||
Other income (expense) | 2 | 1 | 1 | 100.0 | % | |||||||||||
Total other income (expenses) | 66,618 | (6,539 | ) | 73,157 | NM | |||||||||||
Net income (loss) | 85,049 | (6,603 | ) | 91,652 | NM | |||||||||||
Net income attributable to noncontrolling interest | 289 | 38 | (251 | ) | (660.5 | )% | ||||||||||
Net income (loss) attributable to controlling interest | 84,760 | (6,641 | ) | 91,401 | NM |
NM = A percentage calculation is not meaningful due to a change in signs or a zero-value denominator
8
Energy revenue
Revenue from energy increased by $21.8 million, or 34.9%, for the six months ended June 30, 2021 compared to the same period in 2020. This change was attributable primarily to higher RIN pricing, higher natural gas and power commodity revenue. The average D3 RIN index price for the period from January 1, 2021 to June 30, 2021 was $3.1/gallon, up from $1.3/gallon for the same period in 2020. The average realized ISONE/NYISO commodity pricing from January 1, 2021 to June 30, 2021 was $34.6/MWh as compared to $18.1/MWh for the same period in 2020.
Construction Revenue
Construction revenue decreased by $7.2 million, or 99.7%, for the six months ended June 30, 2021 compared to the same period in 2020. This change was attributable primarily to the absence of joint venture construction activity in 2021 consistent with the plan compared to 2020, which included revenue from construction at South Shelby RNG facility.
Cost of Energy
Cost of energy related products increased by $5.1 million, or 14.2%, for the six months ended June 30, 2021 compared to the same period in 2020. This change was attributable primarily to higher royalty and electric transmission expenses partially offset by lower EMRNG replacement product, electric maintenance costs and other miscellaneous expenses.
Cost of Construction
Cost of construction decreased by $6.9 million, or 99.7%, for the six months ended June 30, 2021 compared to the same period in 2020. This decrease was in line with decrease in construction revenue for reasons explained above.
Depreciation, Amortization and Accretion
Depreciation, amortization and accretion decreased by $4.3 million, or 27.4%, for the six months ended June 30, 2021 compared to the same period in 2020. This change was attributable primarily to lower depreciation and amortization of LESPH assets which were categorized as ‘assets held for sale’.
Gain on disposal of assets
Gain on disposal of asset of $1.3 million for six months ended June 30, 2021 is attributable to gain from transfer of intercompany liabilities to Aria offset by $0.5 million impairment recorded as a valuation allowance in relation to the sale of LESPH. No assets were impaired or gain on loss of assets recorded in the six months ended June 30, 2020.
General and Administrative Expenses
General and administrative expenses increased by $3.4 million, or 35.6%, for the six months ended June 30, 2021 compared to the same period in 2020. This change was attributable primarily to higher company sale expenses, LESPH debt forbearance expenses and higher contracted services, information technology and other miscellaneous expenses.
Equity in Income of Joint Ventures
Equity in income of joint ventures increased by $9.9 million, or 286.7%, for the six months ended June 30, 2021 compared to the same period in 2020. This change was attributable primarily to increased RNG production from the addition of South Shelby RNG facility at Mavrix, LLC, a joint venture, along with higher RIN prices.
Interest Expense
Interest expense decreased by $1.0 million, or 10.2%, for the six months ended June 30, 2021 compared to the same period in 2020. This change was attributable primarily to a decline in average outstanding balances on our existing revolving credit facility and term loan B, and to lower interest rates.
9
Gain (loss) on natural gas Swap Contracts
Gain on natural gas swap contracts was $0.6 million for the six months ended June 30, 2021, increased from a loss of $0.3 million for the six months ended June 30, 2020. This change was attributable primarily to rising natural gas prices.
Gain on extinguishment of debt
Sale of LESPH assets, completed on June 10, 2021 resulted in release of lender claims and discharge of the obligations of LESPH under the term loan agreement. The extinguishment of debt obligation resulted in a net gain of $61.4 million.
Other Income (expense)
Other income includes unusual transactions not part of the ordinary course of doing business. Other income and its changes were not material during the six months ended June 30, 2021 or the six months ended June 30, 2020.
Non-controlling Interest
Income attributable to non-controlling interest was $0.3 million for the six months ended June 30, 2021 compared to $0.0 million for the six months ended June 30, 2020. The change was attributable primarily to extinguishment of liabilities resulting from the sale of LESPH assets.
Adjusted EBITDA
For the Six Months Ended June 30, 2021 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Total revenue | $ | 54,669 | $ | 27,931 | $ | — | $ | 82,600 | ||||||||
Net income (loss) | 38,773 | 64,925 | (18,938 | ) | 84,760 | |||||||||||
EBITDA | 43,892 | 71,779 | (10,236 | ) | 105,435 | |||||||||||
Adjusted EBITDA | 41,411 | 9,328 | (7,065 | ) | 43,674 | |||||||||||
Total assets | 168,572 | 143,533 | 36,164 | 348,269 | ||||||||||||
Capital expenditures and investments in joint ventures | 7,507 | 361 | 93 | 7,961 |
The table below sets forth the reconciliation of Net income (loss) to Adjusted EBITDA:
For the Six Months Ended June 30, 2021 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Net income (loss) | $ | 38,773 | $ | 64,925 | $ | (18,938 | ) | $ | 84,760 | |||||||
Depreciation, amortization and accretion | 5,119 | 6,854 | 26 | 11,999 | ||||||||||||
Interest expense | — | — | 8,676 | 8,676 | ||||||||||||
EBITDA | 43,892 | 71,779 | (10,236 | ) | 105,435 | |||||||||||
Gain on disposal of assets | — | (1,347 | ) | — | (1,347 | ) | ||||||||||
Net derivative activity | (1,015 | ) | — | — | (1,015 | ) | ||||||||||
Equity in income of joint ventures | (11,523 | ) | (1,802 | ) | — | (13,325 | ) | |||||||||
Return on investment in joint ventures | 10,057 | 2,109 | — | 12,166 | ||||||||||||
Debt forbearance costs | — | — | 990 | 990 | ||||||||||||
Gain on extinguishment of debt | — | (61,411 | ) | — | (61,411 | ) | ||||||||||
Costs related to sale of equity | — | — | 2,181 | 2,181 | ||||||||||||
Adjusted EBITDA | $ | 41,411 | $ | 9,328 | $ | (7,065 | ) | $ | 43,674 |
10
Adjusted EBITDA
For the Six Months Ended June 30, 2020 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Total revenue | $ | 38,825 | $ | 29,236 | $ | — | $ | 68,061 | ||||||||
Net income (loss) | 11,068 | (1,002 | ) | (16,707 | ) | (6,641 | ) | |||||||||
EBITDA | 16,099 | 10,115 | (6,989 | ) | 19,225 | |||||||||||
Adjusted EBITDA | 15,213 | 11,290 | (6,394 | ) | 20,109 | |||||||||||
Total assets | 148,786 | 251,388 | 14,548 | 414,722 | ||||||||||||
Capital expenditures and investments in joint ventures | 2,780 | 121 | (387 | ) | 2,514 |
The table below sets forth the reconciliation of Net income (loss) to Adjusted EBITDA:
For the Six Months Ended June 30, 2020 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Net income (loss) | $ | 11,068 | $ | (1,002 | ) | $ | (16,707 | ) | $ | (6,641 | ) | |||||
Depreciation, amortization and accretion | 5,031 | 11,117 | 42 | 16,190 | ||||||||||||
Interest expense | — | — | 9,676 | 9,676 | ||||||||||||
EBITDA | 16,099 | 10,115 | (6,989 | ) | 19,225 | |||||||||||
Impairment of assets | — | — | — | — | ||||||||||||
Net derivative activity | (421 | ) | — | — | (421 | ) | ||||||||||
Equity in income of joint ventures | (1,765 | ) | (1,681 | ) | — | (3,446 | ) | |||||||||
Return on investment in joint ventures | 1,300 | 2,856 | — | 4,156 | ||||||||||||
Debt forbearance costs | — | — | 491 | 491 | ||||||||||||
Costs related to sale of equity | — | — | 104 | 104 | ||||||||||||
Adjusted EBITDA | $ | 15,213 | $ | 11,290 | $ | (6,394 | ) | $ | 20,109 |
Adjusted EBITDA for the six months ended June 30, 2021 was $43.7 million compared to $20.1 million for the six months ended June 30, 2020. This increase was attributable primarily to higher RNG and electric pricing and higher RNG production.
Revenue for the RNG segment for the six months ended June 30, 2021 was $54.7 million compared to $38.8 million for the six months ended June 30, 2020, an increase of $15.9 million, or 41%. Higher RNG prices, principally RINs, contributed $22.5 million to the positive variance offset by lower construction revenue of $7.2 million. Higher RNG production of $0.4 million and other immaterial factors accounted for the remaining change.
Net income for the RNG segment for the six months ended June 30, 2021 was $38.8 million compared to $11.1 million for the six months ended June 30, 2020, an increase of $27.7 million, or 250.3%. Higher RNG energy revenue discussed above contributed $22.9 million and equity earnings in a nonconsolidated subsidiary contributed $9.6 million offset by higher royalty expense linked to revenue and lower net income from construction activity.
Net income for the LFGTE segment for the six months ended June 30, 2021 was $64.9 million compared to a net loss of $1.0 million for the six months ended June 30, 2020, an increase of $65.9 million. The increase was attributable primarily to gain from extinguishment of debt of $61.4 million and lower depreciation and amortization of $4.3 million, at Aria’s LESPH subsidiary. Other immaterial factors accounted for remaining change.
Adjusted EBITDA is a non-GAAP financial measure and should not be considered in isolation, as a substitute for, or as superior to GAAP financial measures. For additional information and limitations relating to Adjusted EBITDA, see “Key Metrics — Adjusted EBITDA.”
11
Comparison of the Years ended December 31, 2020 and 2019
The following table presents certain information relating to our operating results for the years ended December 31, 2020 and December 31, 2019 (in thousands):
Years Ended December 31, | ||||||||||||||||
2020 | 2019 | $ Change | % Change | |||||||||||||
Revenue | ||||||||||||||||
Energy revenue | $ | 132,580 | $ | 120,489 | 12,091 | 10.0 | % | |||||||||
Construction revenue | 9,983 | 12,497 | (2,514 | ) | (20.1 | )% | ||||||||||
Amortization of intangibles and below-market contracts | (3,682 | ) | (3,669 | ) | (13 | ) | (0.4 | )% | ||||||||
Total revenue | 138,881 | 129,317 | 9,564 | 7.4 | % | |||||||||||
Cost of revenue | ||||||||||||||||
Cost of energy | 72,519 | 73,537 | 1,018 | 1.4 | % | |||||||||||
Cost of construction | 9,507 | 11,902 | 2,395 | 20.1 | % | |||||||||||
Depreciation, amortization and accretion | 30,564 | 32,092 | 1,528 | 4.8 | % | |||||||||||
Total cost of revenue | 112,590 | 117,531 | 4,941 | 4.2 | % | |||||||||||
Gross profit | 26,291 | 11,786 | 14,505 | 123.1 | % | |||||||||||
Impairment of assets | 25,293 | 1,634 | (23,659 | ) | (1,447.9 | )% | ||||||||||
General and administrative expenses | 20,782 | 18,810 | (1,972 | ) | (10.5 | )% | ||||||||||
Operating loss | (19,784 | ) | (8,658 | ) | (11,126 | ) | (128.5 | )% | ||||||||
Other income (expense) | ||||||||||||||||
Equity in income of joint ventures | 9,298 | 4,378 | 4,920 | 112.4 | % | |||||||||||
Interest expense, net | (19,305 | ) | (22,053 | ) | 2,748 | 12.5 | % | |||||||||
Gain (loss) on swap contracts | (135 | ) | (619 | ) | 484 | 78.2 | % | |||||||||
Other income (expense) | 3 | 5 | (2 | ) | (40.0 | )% | ||||||||||
Total other expenses | (10,139 | ) | (18,289 | ) | 8,150 | 44.6 | % | |||||||||
Net loss | (29,923 | ) | (26,947 | ) | (2,976 | ) | (11.0 | )% | ||||||||
Net income attributable to noncontrolling interest | 78 | 84 | 6 | 7.1 | % | |||||||||||
Net loss attributable to controlling interest | (30,001 | ) | (27,031 | ) | (2,970 | ) | (11.0 | )% |
Energy revenue
Revenue from energy increased by $12.1 million, or 10.0%, for the year ended December 31, 2020 compared to the year ended December 31, 2019. This change was attributable primarily to higher RIN pricing combined with higher RNG production, higher REC and capacity revenue partially offset by lower LCFS and power sale revenue. The average D3 RIN index price for 2020 was $1.49/gallon up from $1.15/gallon in 2019. The average realized ISONE/NYISO REC pricing in 2020 was $29.2/MWh as compared to $21.2/MWh in 2019. Increase in capacity revenues is due to full year ISONE forward capacity market participation as compared to partial year participation in 2019 as Aria couldn’t participate in 2018-19 forward capacity commitment period.
Construction Revenue
Service revenue decreased by $2.5 million, or 20.1%, to $10.0 million for the year ended December 31, 2020 compared to the year ended December 31, 2019. This change was attributable primarily to lower construction activity at South Shelby RNG plant as planned as major part of work was completed in 2019.
Cost of Energy
Cost of energy related products decreased by $1.0 million, or 1.4%, for the year ended December 31, 2020 compared to the year ended December 31, 2019. This change was attributable primarily to lower plant electricity, gas purchase, electric transmission expenses and other miscellaneous expenses partially offset by higher maintenance and royalty costs.
12
Cost of Construction
Cost of construction decreased by $2.4 million, or 20.1%, to $9.5 million for the year ended December 31, 2020 compared to the year ended December 31, 2019. This decrease was in line with decrease in construction revenue for reasons explained above.
Depreciation, Amortization and Accretion
Depreciation, amortization and accretion decreased by $1.5 million, or 4.8%, to $30.6 million for the year ended December 31, 2020 compared to the year ended December 31, 2019. This decrease was attributable primarily to lower amortization of gas rights.
Impairment expense
Aria performed an impairment analysis related to the cooperative sale process, which was initiated in 2020, of LESPH’s assets and liabilities. As discussed above, Aria entered into a definitive Membership Interest Purchase Agreement with Energy Power Investment Company LLC on March 1, 2021. Given the characteristics of the cooperative sale process, this was treated as a separate transaction from the settlement of the debt (through the execution of the Mutual Release Agreement). Since the former will result in a loss, it is recognized as an impairment charge of $25.3 million in 2020. The gain resulting from the settlement of the debt will be recognized in the second fiscal quarter of 2021.
General and Administrative Expenses
General and administrative expenses increased by $2.0 million, or 10.5%, to $20.8 million for the year ended December 31, 2020 compared to the year ended December 31, 2019. This increase was attributable primarily to higher contracted services (salaries and benefits) and LESPH debt forbearance expenses.
Equity in Income of Joint Ventures
Equity in income of joint ventures increased by $4.9 million, or 112.4%, to $9.3 million for the year ended December 31, 2020 compared to the year ended December 31, 2019. This increase was attributable primarily to increased RNG production at Mavrix, LLC, a joint venture, along with higher RIN prices.
Interest Expense
Interest expense decreased by $2.7 million, or 12.5%, to $19.3 million for the year ended December 31, 2020 compared to the year ended December 31, 2019. This decrease was attributable primarily to a decline in average outstanding balances on our existing revolving credit facility and term loan B, and to lower interest rates.
Gain (loss) on natural gas Swap Contracts
Loss on interest rate swap contracts was $0.1 million for the year ended December 31, 2020, decreased from a loss of $0.6 million for the year ended December 31, 2019. This change was attributable primarily to rising natural gas prices.
Other Income
Other income includes unusual transactions not part of the ordinary course of doing business. Other income and its changes were not material during either year.
Non-controlling Interest
Income attributable to non-controlling interest was virtually unchanged at $0.0 million for the year ended December 31, 2020 compared to the year ended December 31, 2019.
13
Adjusted EBITDA
For the year ended December 31, 2020 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Total revenue | $ | 81,559 | $ | 57,322 | $ | — | $ | 138,881 | ||||||||
Net income (loss) | 30,459 | (26,126 | ) | (34,334 | ) | (30,001 | ) | |||||||||
EBITDA | 40,592 | (4,531 | ) | (14,941 | ) | 21,120 | ||||||||||
Adjusted EBITDA | 38,784 | 25,137 | (12,686 | ) | 51,235 | |||||||||||
Total assets | 158,790 | 213,533 | 20,596 | 392,919 | ||||||||||||
Capital expenditures and investments in joint ventures | 14,364 | 980 | — | 15,344 |
The table below sets forth the reconciliation of Net income (loss) to Adjusted EBITDA:
For the year ended December 31, 2020 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Net income (loss) | $ | 30,459 | $ | (26,126 | ) | $ | (34,334 | ) | $ | (30,001 | ) | |||||
Depreciation, amortization and accretion | 10,133 | 21,595 | 74 | 31,802 | ||||||||||||
Interest expense | — | — | 19,319 | 19,319 | ||||||||||||
EBITDA | 40,592 | (4,531 | ) | (14,941 | ) | 21,120 | ||||||||||
Impairment of assets | — | 25,293 | — | 25,293 | ||||||||||||
Net derivative activity | (1,151 | ) | — | — | (1,151 | ) | ||||||||||
Equity in income of joint ventures | (6,107 | ) | (3,191 | ) | — | (9,298 | ) | |||||||||
Return on investment in joint ventures | 5,450 | 7,566 | — | 13,016 | ||||||||||||
Debt forbearance costs | — | — | 1,815 | 1,815 | ||||||||||||
Costs related to sale of equity | — | — | 440 | 440 | ||||||||||||
Adjusted EBITDA | $ | 38,784 | $ | 25,137 | $ | (12,686 | ) | $ | 51,235 |
For the year ended December 31, 2019 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Total revenue | $ | 73,273 | $ | 56,044 | $ | — | $ | 129,317 | ||||||||
Net income (loss) | 14,314 | (5,966 | ) | (35,379 | ) | (27,031 | ) | |||||||||
EBITDA | 21,503 | 20,033 | (13,121 | ) | 28,415 | |||||||||||
Adjusted EBITDA | 25,093 | 24,596 | (12,381 | ) | 37,308 | |||||||||||
Total assets | 150,667 | 259,911 | 15,564 | 426,142 | ||||||||||||
Capital expenditures and investments in joint ventures | 14,579 | 1,449 | — | 16,028 |
The table below sets forth the reconciliation of Net income (loss) to Adjusted EBITDA:
For the year ended December 31, 2019 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Net income (loss) | $ | 14,314 | $ | (5,966 | ) | $ | (35,379 | ) | $ | (27,031 | ) | |||||
Depreciation, amortization and accretion | 7,189 | 25,999 | 129 | 33,317 | ||||||||||||
Interest expense | — | — | 22,129 | 22,129 | ||||||||||||
EBITDA | 21,503 | 20,033 | (13,121 | ) | 28,415 | |||||||||||
Impairment of assets | — | 1,634 | — | 1,634 | ||||||||||||
Net derivative activity | (126 | ) | — | — | (126 | ) | ||||||||||
Equity in income of joint ventures | (664 | ) | (3,714 | ) | — | (4,378 | ) | |||||||||
Return on investment in joint ventures | 4,380 | 6,643 | — | 11,023 | ||||||||||||
Debt forbearance costs | — | — | 623 | 623 | ||||||||||||
Costs related to sale of equity | — | — | 117 | 117 | ||||||||||||
Adjusted EBITDA | $ | 25,093 | $ | 24,596 | $ | (12,381 | ) | $ | 37,308 |
14
Adjusted EBITDA for the year ended December 31, 2020 was $51.2 million compared to $37.3 million for the year ended December 31, 2019. The increase in Adjusted EBITDA during 2020 as compared to 2019 was attributable primarily to higher RNG and electric pricing and increased RNG production.
Revenue for the RNG segment for the year ended December 31, 2020 was $81.6 million compared to $73.3 million for the year ended December 31, 2019, an increase of $8.3 million, or 11%. Higher RNG prices, principally RINs, contributed $5.6 million to the positive variance; increases in RNG volumes sold contributed another $5.0 million. Construction revenue ($2.5 million decrease) and other immaterial factors accounted for the remaining change.
Net income for the RNG segment for the year ended December 31, 2020 was $30.5 million compared to $14.3 million for the year ended December 31, 2019, an increase of $16.1 million, or 113%. Higher RNG revenue (price and volume impacts), discussed above, contributed $10.1 million, and equity earnings in a nonconsolidated subsidiary contributed $5.4 million. The remainder was made up of immaterial items.
Net loss for the LFGTE segment for the year ended December 31, 2020 was $26.1 million compared to a net loss of $6.0 million for the year ended December 31, 2019. The decline was attributable to an increase in impairment of assets, partially offset by lower depreciation and amortization, at Aria’s LESPH subsidiary.
Adjusted EBITDA is a non-GAAP financial measure and should not be considered in isolation, as a substitute for, or as superior to GAAP financial measures. For additional information and limitations relating to Adjusted EBITDA, see “Key Metrics — Adjusted EBITDA.”
Comparison of the Years ended December 31, 2019 and 2018
The following table presents certain information relating to our operating results for the years ended December 31, 2019 and December 31, 2018 (in thousands)
Years Ended December 31, | ||||||||||||||||
2019 | 2018 | $ Change | % Change | |||||||||||||
Revenue | ||||||||||||||||
Energy revenue | $ | 120,489 | $ | 155,112 | (34,623 | ) | (22.3 | )% | ||||||||
Construction revenue | 12,497 | 13,172 | (675 | ) | (5.1 | )% | ||||||||||
Amortization of intangibles and below-market contracts | (3,669 | ) | (3,119 | ) | (550 | ) | (17.6 | )% | ||||||||
Total revenue | 129,317 | 165,165 | (35,848 | ) | (21.7 | )% | ||||||||||
Cost of revenue | ||||||||||||||||
Cost of energy | 73,537 | 79,899 | 6,362 | 8.0 | % | |||||||||||
Cost of construction | 11,902 | 12,596 | 694 | 5.5 | % | |||||||||||
Depreciation, amortization and accretion | 32,092 | 34,154 | 2,062 | 6.0 | % | |||||||||||
Total cost of revenue | 117,531 | 126,649 | 9,118 | 7.2 | % | |||||||||||
Gross profit | 11,786 | 38,516 | (26,730 | ) | (69.4 | )% | ||||||||||
Impairment of assets | 1,634 | 26,167 | 24,533 | 93.8 | % | |||||||||||
General and administrative expenses | 18,810 | 21,049 | 2,239 | 10.6 | % | |||||||||||
Operating income (loss) | (8,658 | ) | (8,700 | ) | 42 | 0.5 | % | |||||||||
Other income (expense) | ||||||||||||||||
Equity in income of joint ventures | 4,378 | 3,260 | 1,118 | 34.3 | % | |||||||||||
Interest expense, net | (22,053 | ) | (20,431 | ) | (1,622 | ) | (7.9 | )% | ||||||||
Gain (loss) on swap contracts | (619 | ) | 1,727 | (2,346 | ) | (135.8 | )% | |||||||||
Loss on disposal of assets | — | (556 | ) | 556 | 100.0 | % | ||||||||||
Other income (expense) | 5 | 9 | (4 | ) | (44.4 | )% | ||||||||||
Total other expenses | (18,289 | ) | (15,991 | ) | (2,298 | ) | (14.4 | )% | ||||||||
Net loss | (26,947 | ) | (24,691 | ) | (2,256 | ) | (9.1 | )% | ||||||||
Net income attributable to noncontrolling interest | 84 | 67 | (17 | ) | (25.4 | )% | ||||||||||
Net loss attributable to controlling interest | (27,031 | ) | (24,758 | ) | (2,273 | ) | (9.2 | )% |
15
Energy revenue
Revenue from energy related products decreased by $34.6 million, or 22.3%, for the year ended December 31, 2019 compared to the year ended December 31, 2018. This change was attributable primarily to lower RIN pricing and lower RNG production, lower power sale revenue and natural gas revenue. 2019 average index D3 RIN price was $1.15/gallon compared to $2.29/gallon in 2018.
Construction Revenue
Construction revenue decreased by $0.7 million, or 5.1%, to $12.5 million for the year ended December 31, 2019 compared to the year ended December 31, 2018. This change was attributable primarily to lower construction activity and related capital expenditure incurred towards building new Mavrix RNG facilities.
Cost of Energy
Cost of energy related products decreased by $6.4 million, or 8.0%, for the year ended December 31, 2019 compared to the year ended December 31, 2018. This change was attributable primarily to lower royalty resulting from lower RIN prices and lower RNG production partially offset by higher maintenance, contracted services and gas transportation expenses.
Cost of Construction
Cost of construction revenues decreased by $0.7 million, or 5.5%, to $11.9 million for the year ended December 31, 2019 compared to the year ended December 31, 2018. This decrease was in line with the decrease in construction revenue for the reasons explained above.
Depreciation, Amortization and Accretion
Depreciation, amortization and accretion decreased by $2.1 million, or 6.0%, to $32.1 million for the year ended December 31, 2019 compared to the year ended December 31, 2018. This decrease was attributable primarily to lower amortization of gas rights.
Impairment expense
There were impairment charges recorded in 2019 of $1.6 million: $1.3 million was charged to intangible assets and the remaining was charged to property and equipment. An impairment charge of $26.2 million was recognized in 2018. Specifically, a $20.5 million impairment was charged to intangible assets and the remaining was charged to property and equipment.
General and Administrative Expenses
General and administrative expenses decreased by $2.2 million, or 10.6%, to $18.8 million for the year ended December 31, 2019 compared to the year ended December 31, 2018. This decrease was attributable primarily to lower debt forbearance and company sale expenses.
Equity in Income of Joint Ventures
Equity in income of joint ventures increased by $1.1 million, or 34.3%, to $4.4 million for the year ended December 31, 2019 compared to the year ended December 31, 2018. This increase was attributable primarily to higher income from our Sunshine joint venture resulting from lower depreciation in 2019.
16
Interest Expense
Interest expense increased by $1.6 million, or 7.9%, to $22.1 million for the year ended December 31, 2019 compared to the year ended December 31, 2018. This increase was attributable primarily to higher interest rates on LESPH debt due to the default.
Gain (loss) on Swap Contracts
Loss on swap contracts was $0.6 million for the year ended December 31, 2019, up from a gain of $1.7 million for the year ended December 31, 2018. This change was attributable primarily to termination of in the money interest rate swap and decreasing natural gas prices for natural gas swap.
Other Income
Other income includes unusual transactions not part of the ordinary course of doing business. There were no material items in other income during either year.
Non-controlling Interest
Income attributable to non-controlling interest was virtually unchanged at $0.0 million for the year ended December 31, 2019 compared to the year ended December 31, 2018.
Adjusted EBITDA
For the year ended December 31, 2019 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Total revenue | $ | 73,273 | $ | 56,044 | $ | — | $ | 129,317 | ||||||||
Net income (loss) | 14,314 | (5,966 | ) | (35,379 | ) | (27,031 | ) | |||||||||
EBITDA | 21,503 | 20,033 | (13,121 | ) | 28,415 | |||||||||||
Adjusted EBITDA | 25,093 | 24,596 | (12,381 | ) | 37,308 | |||||||||||
Total assets | 150,667 | 259,911 | 15,564 | 426,142 | ||||||||||||
Capital expenditures and investments in joint ventures | 14,579 | 1,449 | — | 16,028 |
The table below sets forth the reconciliation of Net income (loss) to Adjusted EBITDA:
For the year ended December 31, 2019 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Net income (loss) | $ | 14,314 | $ | (5,966 | ) | $ | (35,379 | ) | $ | (27,031 | ) | |||||
Depreciation, amortization and accretion | 7,189 | 25,999 | 129 | 33,317 | ||||||||||||
Interest expense | — | — | 22,129 | 22,129 | ||||||||||||
EBITDA | 21,503 | 20,033 | (13,121 | ) | 28,415 | |||||||||||
Impairment of assets | — | 1,634 | — | 1,634 | ||||||||||||
Net derivative activity | (126 | ) | — | — | (126 | ) | ||||||||||
Equity in income of joint ventures | (664 | ) | (3,714 | ) | — | (4,378 | ) | |||||||||
Return on investment in joint ventures | 4,380 | 6,643 | — | 11,023 | ||||||||||||
Debt forbearance costs | — | — | 623 | 623 | ||||||||||||
Costs related to sale of equity | — | — | 117 | 117 | ||||||||||||
Adjusted EBITDA | $ | 25,093 | $ | 24,596 | $ | (12,381 | ) | $ | 37,308 |
17
For the year ended December 31, 2018 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Total revenue | $ | 102,844 | $ | 62,321 | $ | — | $ | 165,165 | ||||||||
Net income (loss) | 41,304 | (30,975 | ) | (35,087 | ) | (24,758 | ) | |||||||||
EBITDA | 48,085 | (2,980 | ) | (14,401 | ) | 30,704 | ||||||||||
Adjusted EBITDA | 47,139 | 25,586 | (12,422 | ) | 60,303 | |||||||||||
Total assets | 157,825 | 282,906 | 24,973 | 465,704 | ||||||||||||
Capital expenditures and investments in joint ventures | 26,325 | 949 | — | 27,274 |
The table below sets forth the reconciliation of Net income (loss) to Adjusted EBITDA:
For the year ended December 31, 2018 | ||||||||||||||||
RNG | LFGTE | Corporate | Total | |||||||||||||
Net income (loss) | $ | 41,304 | $ | (30,975 | ) | $ | (35,087 | ) | $ | (24,758 | ) | |||||
Depreciation, amortization and accretion | 6,781 | 27,995 | 52 | 34,828 | ||||||||||||
Interest expense | — | — | 20,634 | 20,634 | ||||||||||||
EBITDA | 48,085 | (2,980 | ) | (14,401 | ) | 30,704 | ||||||||||
Impairment of assets | — | 26,167 | — | 26,167 | ||||||||||||
Net derivative activity | (875 | ) | — | (852 | ) | (1,727 | ) | |||||||||
Equity in income of joint ventures | (2,427 | ) | (833 | ) | — | (3,260 | ) | |||||||||
Return on investment in joint ventures | 1,800 | 3,232 | — | 5,032 | ||||||||||||
Loss on disposal of assets | 556 | — | — | 556 | ||||||||||||
Debt forbearance costs | — | — | 1,792 | 1,792 | ||||||||||||
Costs related to sale of equity | — | — | 1,039 | 1,039 | ||||||||||||
Adjusted EBITDA | $ | 47,139 | $ | 25,586 | $ | (12,422 | ) | $ | 60,303 |
Adjusted EBITDA for the year ended December 31, 2019 was $37.3 million compared to $60.3 million for the year ended December 31, 2018. The decrease in Adjusted EBITDA during 2019 as compared to 2018 was attributable primarily to declines in production and RNG pricing.
Revenue from RNG segment for the year ended December 31, 2019 was $73.3 million compared to $102.8 million for year ended December 31, 2018, a decrease of $29.5 million, or 29%. Lower RNG prices, principally RINs, contributed to $21.2 million to the negative variance; decrease in RNG volume sold contributed another $7.9 million. Other immaterial factors accounted for remaining change
Net income for RNG segment for the year ended December 31, 2019 was $14.3 million compared to $41.3 million for the year ended December 31, 2018, a decrease of $27.0 million or 65%. Lower RNG revenue (price and volume impacts), discussed above contributed to $29.1 million, and equity earnings in a nonconsolidated subsidiary contributed another $1.8 million to the negative variances partially offset by lower royalty linked to the revenue.
Revenue from LFGTE segment for the year ended December 31, 2019 was $56.0 million compared to $62.3 million for the year ended December 31, 2018, a decrease of $6.3 million or 10%. Lower pricing, primarily power commodity prices contributed to $5.0 million to the variance; decrease in electric production caused $0.5 million. Other immaterial factors accounted for the remaining change.
Net loss for LFGTE segment for the year ended December 31, 2019 was $6.0 million compared to a net loss of $31.0 million for the year ended December 31, 2018. The decrease in loss was attributable to lower impairment and depreciation and amortization in 2019, higher equity earnings in nonconsolidated subsidiaries compared to 2018, partially offset by lower revenue discussed above.
Adjusted EBITDA is a non-GAAP financial measure and should not be considered in isolation, as a substitute for, or as superior to GAAP financial measures. For additional information and limitations relating to Adjusted EBITDA, see “Key Metrics — Adjusted EBITDA.”
18
Liquidity and Capital Resources
Our principal liquidity requirements are to finance current operations, fund capital expenditures, including construction projects and acquisitions from time to time, and to service our debt. Historically, our operations were financed through internally generated cash flows as well as corporate and/or project-level borrowings, including tax equity investments, to satisfy our capital expenditure requirements. As a normal part of our business, depending on market conditions, we have from time to time considered opportunities to repay, redeem, repurchase or refinance our indebtedness. Changes in our operating plans, lower than anticipated revenues, increased expenses, acquisitions or other events may cause the Combined Company to seek additional debt or equity financing in future periods. There can be no guarantee that financing will be available on acceptable terms or at all.
As of June 30, 2021, our available liquidity was $35.7 million. In addition, as of June 30, 2021, we had approximately $24.1 million of borrowing capacity remaining under our revolving credit facility as discussed in Note 7, Long-Term Debt, to our unaudited financial statements included elsewhere in this Form 8-K. As of December 31, 2020, our available liquidity was $14.3 million. In addition, as of December 31, 2020, we had approximately $20.8 million of borrowing capacity remaining under our revolving credit facility as discussed in Note 7, Long-Term Debt, to our audited financial statements included elsewhere in this Form 8-K.
As of both June 30, 2021 and December 31, 2020, we owed $138.0 million on the term loan B under our existing credit facility. The existing credit facility was repaid and terminated in connection with the Business Combination.
Following the consummation of the Business Combination, the liquidity needs of the Combined Company will be determined based on the needs and strategy of the combined business, as discussed in the sections of the Proxy Statement entitled “Information about the Combined Company” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Archaea.”
Cash Flows
We use traditional measures of cash flow, including net cash provided by operating activities, net cash used in investing activities and net cash used in financing activities, as well as cash available for distribution to evaluate our periodic cash flow results.
The following table reflects the changes in cash flows for the comparative periods (in thousands):
Six Months Ended June 30, | Year Ended December 31, | |||||||||||||||||||
2021 | 2020 | 2020 | 2019 | 2018 | ||||||||||||||||
Net cash provided by operating activities | $ | 32,092 | $ | 8,054 | $ | 31,029 | $ | 20,725 | $ | 46,230 | ||||||||||
Net cash used in investing activities | (7,961 | ) | (2,514 | ) | (15,344 | ) | (16,028 | ) | (27,274 | ) | ||||||||||
Net cash used in financing activities | (2,689 | ) | (6,553 | ) | (8,509 | ) | (12,630 | ) | (26,798 | ) | ||||||||||
Total increase (decrease) in cash and cash equivalents | $ | 21,442 | $ | (1013 | ) | $ | 7,176 | $ | (7,933 | ) | $ | (7,842 | ) |
Net Cash Provided by Operating Activities
The change to net cash provided by operating activities is driven primarily by RNG and power production, pricing, operating expenses, interest payment and changes in working capital. The change to net cash provided by operating activities for the six months ended June 30, 2021 is primarily driven by higher RNG production and higher RIN, power and natural gas commodity pricing. The change to net cash provided by operating activities for the six months ended June 30, 2020 is primarily driven by lower RIN pricing and RNG production.
The change to net cash provided by operating activities for the year ended December 31, 2020 is primarily driven by higher RNG production and higher RIN and REC pricing. The change to net cash provided by operating activities for the year ended December 31, 2019 is primarily driven by lower RNG production and RIN pricing.
19
Net Cash Used in Investing Activities
The change to net cash used by investing activities is primarily driven by capital expenditures incurred to build new facilities and to expand or improve existing facilities. The change to net cash used by investing activities for the six months ended June 30, 2021 is primarily driven by contributions to Mavrix for the construction of RNG Moovers dairy digester project and for development of other new digester project. The change to net cash used by investing activities for the six months ended June 30, 2020 is primarily driven by contributions to Mavrix for construction of South Shelby RNG facility and capital improvements at other operating facilities.
The change to net cash used by investing activities for the year ended December 31, 2020 is primarily driven by contributions to Mavrix for the construction of South Shelby RNG plant and RNG Moovers. The change to net cash used by investing activities for the year ended December 31, 2019 is primarily driven by contributions to Mavrix for the construction of South Shelby RNG plant and capital improvements at KCLFG RNG facility.
Net Cash Used in Financing Activities
The change to net cash used by financing activities is primarily driven by distributions to shareholders allowed under the credit agreements, scheduled debt repayments, mandatory cash sweeps and withdrawal/repayment of the revolving credit facility. The change to net cash provided by financing activities for the six months ended June 30, 2021 is driven by repayment of LESPH closing cash to the lenders. The change to net cash provided by financing activities for the six months ended June 30, 2020 is primarily driven by $4 million net repayment of outstanding revolving credit facility and $2.4 million repayment of term loan debt.
The change to net cash provided by financing activities for the year ended December 31, 2020 is primarily driven by $4.4 million repayment of term loan debt and a $4.0 million net repayment of the revolving credit facility. The change to net cash provided by financing activities for the year ended December 31, 2019 is primarily driven by $10.9 million of distributions to shareholders and $5.6 million repayment of term loan debt offset by $4.0 million withdrawal of the revolving credit facility.
Indebtedness
Aria Energy Operating LLC had a credit facility, which included a revolving credit facility and a term loan B. Outstanding letters of credit as of June 30, 2021 were $16.1 million, all of which were undrawn. Outstanding letters of credit as of December 31, 2020, 2019 and 2018 were $19.4 million, $21.3 million and $19.6 million, respectively, all of which were undrawn. Amount drawn under the revolving credit facility as of June 30, 2021 was $0.0 million. Amounts drawn under the revolving credit facility as of December 31, 2020, 2019 and 2018 were $0.0 million, $4.0 million and $0.0 million, respectively.
Amount outstanding under the term loan B at June 30, 2021 was $138.0 million, and the outstanding balance was repaid in full as part of the Business Combination. Amounts outstanding under the term loan B as of December 31, 2020, 2019 and 2018 were $138.0 million, $142.4 million and $148.0 million, respectively.
The Term Loan B matures on May 27, 2022. Currently, Aria does not have a commitment to refinance the term loan or the related revolver and does not have the capability to satisfy the term loan in the normal course of business. As discussed in note 2 to our financial statements, accordingly, the circumstances of the Term Loan B raise substantial doubt about Aria’s ability to continue as a going concern.
The existing credit facility was repaid and terminated in connection with the Business Combination.
Long-term Debt
Our existing long-term debt consists of notes payable summarized below (in thousands):
Six Months Ended June 30, | Year Ended December 31, | |||||||||||||||||||
2021 | 2020 | 2020 | 2019 | 2018 | ||||||||||||||||
Note payable – due May 2022 | 137,978 | 139,978 | 137,978 | 146,385 | 148,018 | |||||||||||||||
Note payable – due October 2020 | — | 102,831 | 102,831 | 102,831 | 102,831 | |||||||||||||||
Total | 137,978 | 242,809 | 240,809 | 249,216 | 250,849 | |||||||||||||||
Less: Current portion | 137,978 | 103,831 | 102,831 | 106,738 | 108,463 | |||||||||||||||
Long term portion | — | 138,978 | 137,978 | 142,478 | 142,386 |
20
In accordance with the associated credit agreement governing our existing credit facility, the above debt has a set minimum maturity schedule. The credit agreement also outlines various factors to achieve a target maturity schedule based on our future cash flows. The balance of the above debt matures under the two schedules as follows (in thousands):
Years Ending | Minimum Maturity Payments | |||
2021 | $ | — | ||
2022 | 137,978 | |||
Total | 137,978 |
Under its credit agreements, Aria Energy Operating LLC is subject to certain financial covenants including maintaining a Net Leverage Ratio and limitations on investments to nonconsolidated subsidiaries. We were in compliance with these financial covenants as of June 30, 2021 and as of December 31, 2020, 2019 and 2018.
Interest Rate Swap and Cap Agreements
We are exposed to certain risks in the normal course of our business operations. The main risks are those relating to the variability of future earnings and cash flows, which are managed through the use of derivatives. All derivative financial instruments are reported in the consolidated balance sheet at fair value.
In particular, interest rate swaps and interest rate caps are used to manage the risk associated with interest rate cash flows on variable rate borrowings.
Currently, we have no interest rate swaps. In 2020, Aria purchased an interest rate cap with a notional amount of $110.0 million and pays when the 1-month LIBOR rate exceeds 1.0%. The cap expires on May 31, 2022.
Natural Gas Swap Agreement
Aria has a natural gas variable to fixed priced swap agreement with an original notional quantity of 4,007,200 MMBtu. The swap agreement provides for a fixed to variable rate swap calculated monthly, until the termination date of the contract, June 30, 2023. The agreement was intended to manage the risk associated with changing commodity prices. Changes in the fair values of natural gas swap are recognized in gain (loss) on swaps and realized losses are recognized as a component of cost of energy expense as summarized in the table below.
June 30, | December 31 | |||||||||||
2021 | 2020 | 2019 | ||||||||||
Natural gas swap liability | $ | 253 | $ | 1,268 | 2,514 |
June 30, | December 31 | |||||||||||
2021 | 2020 | 2019 | ||||||||||
Natural gas swap – unrealized gain (loss) | $ | 556 | $ | (40 | ) | (619 | ) | |||||
Natural gas swap – realized gain | — | 1,286 | 745 | |||||||||
Interest rate CAP – realized loss | — | (95 | ) | — |
Off-Balance Sheet Arrangements
We have not created, and are not party to, any special-purpose or off-balance sheet entities for the purpose of raising capital, incurring debt or operating our business. As of June 30, 2021, we do not have any off-balance sheet arrangements or relationships with entities that are not consolidated into or disclosed on our financial statements that have or are reasonably likely to have a material effect on our financial condition, results of operations, liquidity, capital expenditures or capital resources.
21
Related Party Transactions
Sales of operations and maintenance services, and sales of administrative and other services are made to, and services are purchased from, our 50% owned joint ventures for the six months ended June 30, 2021 and June 30, 2020 and the years ended December 31, 2020, 2019 and 2018 (in thousands):
June 30 | December 31 | |||||||||||||||||||
2021 | 2020 | 2020 | 2019 | 2018 | ||||||||||||||||
Sales of construction services | $ | 24 | $ | 7,246 | 9,983 | 12,497 | 13,172 | |||||||||||||
Sales of operations and maintenance services | 746 | 850 | 1,701 | 1,635 | 1,511 | |||||||||||||||
Sales of administrative and other services | 195 | 200 | 409 | 382 | 336 | |||||||||||||||
Accounts receivable | 473 | 186 | 332 | 299 | 411 | |||||||||||||||
Cost and estimated earnings in excess of billing | — | — | — | 40 |
Critical Accounting Policies
Our discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.
On an ongoing basis, we evaluate these estimates, utilizing historic experience, consultation with experts and other methods we consider reasonable. In any event, actual results may differ substantially from estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.
Our significant accounting policies are summarized in our audited consolidated financial statements included in the Proxy Statement. We identify our most critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.
Impairments of Long-Lived Assets
We evaluate property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or events are:
● | significant decrease in the market price of a long-lived asset; |
● | significant adverse change in the manner an asset is being used or its physical condition; |
● | adverse business climate; |
● | accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset; |
● | current-period loss combined with a history of losses or the projection of future losses; and |
● | change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life. |
22
Long-lived assets, such as property, plant and equipment, and purchased intangible assets subject to amortization, are reviewed for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group be tested for possible impairment, we first compare undiscounted cash flows expected to be generated by that asset or asset group to our carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. We make considerable judgments in the impairment evaluations of long-lived assets; however, the fair value determination is typically the most judgmental part of an impairment evaluation.
We determine the fair value of a reporting unit or a long-lived asset (asset group) by applying the approaches prescribed under the fair value measurement accounting framework. Generally, the market approach and income approach are most relevant in the fair value measurement of our reporting units and long-lived assets; however, due to the lack of available observable market information in many circumstances, we often rely on the income approach. We develop the underlying assumptions consistent with its internal budgets and forecasts for such valuations. Additionally, we use an internal discounted cash flow valuation model (the “DCF model”), based on the principles of present value techniques, to estimate the fair value of our reporting units or long-lived assets under the income approach. The DCF model estimates fair value by discounting our internal budgets and cash flow forecasts, adjusted to reflect market participant assumptions, to the extent necessary, at an appropriate discount rate.
Management applies considerable judgment in selecting several input assumptions during the development of our internal budgets and cash flow forecasts. Examples of the input assumptions that our budgets and forecasts are sensitive to include macroeconomic factors such as growth rates, industry demand, inflation, exchange rates, power prices and commodity prices. Whenever appropriate, management obtains these input assumptions from observable market data sources and extrapolates the market information if an input assumption is not observable for the entire forecast period. Many of these input assumptions are dependent on other economic assumptions, which are often derived from statistical economic models with inherent limitations such as estimation differences.
Revenue Recognition
Electricity
We sell a significant portion of the electricity we generate under the terms of PPAs or other contractual arrangements which is included in energy related products revenue. Revenue is recognized upon the amount of electricity delivered at rates specified under the contracts. Most PPAs are accounted for as operating leases, have no minimum lease payments and all of the rental income under theses leases is recorded as revenue when the electricity is delivered. PPAs that are not accounted for as leases are considered derivatives and we have elected the normal purchase normal sale exception for these contracts, for which we record revenue when electricity is delivered.
Another portion of our electricity is also sold through energy wholesale markets (NYISO, ISO-NE and PJM) into the day-ahead market. Revenue is recognized upon the amount of electricity delivered into the day-ahead market and recognized based on day-ahead market clearing prices.
We also sell our capacity into the month-ahead and three-year ahead markets in the wholesale markets noted above. Capacity revenues are recognized when contractually earned and consist of revenues billed to a third party at a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements.
23
Gas
We sell the gas we generate pursuant to various contractual arrangements which is included in energy related products revenue. Gas sales are accounted for as operating leases, have no minimum lease payments and all of the rental income under theses leases is recorded as revenue when the gas is delivered to the customer.
Renewable Attributes
We also generate RECs as we process electricity. Certain of these energy credits are sold independently in an open market and revenue is recognized at the time production of the energy credit is recognized where an active market and a sales agreement exists for the credits. Revenue from the sale of RECs is included in energy related products revenue.
Aria generates renewable fuel credits called RINs. Pipeline quality renewable natural gas processed from landfill gas qualifies for RINs when delivered to a compressed natural gas fueling station. RINs are similar to RECs on the electric side in that they reflect the value of renewable energy as a means to satisfy regulatory requirements or goals. They are different in that RINs exist pursuant to a national program and not an individual state program. The majority of Aria’s RINs are generated by plants for which Aria has an offtake agreement to sell all of the outputs and are therefore accounted for as operating leases in, with revenue recognized when the fuel is produced and transferred to a third party.
Operation and Maintenance (“O&M”)
We provide O&M services at projects owned by third parties which are included in service revenue. Revenue for these services is recognized upon the services being provided in accordance with contractual arrangements primarily based on the production of electricity from the project.
Below-Market Contract Amortization
Through acquisitions, we have below-market contracts from PPAs and O&M agreements through acquisitions related to the sale of electricity or delivery of services in future periods for which the fair value has been determined to be less (more) than market that are being amortized to revenue over the remaining life of the underlying contract which is included in energy related products revenue.
Construction Type Contracts
We on occasion enter into contracts with affiliates to construct RNG projects. This contract revenue is recorded under the percentage completion method based on cost incurred to date as a percentage of the contract total which is included in service revenue. Revenues generated from these contracts amounted to $10.0 million, $12.5 million and $13.2 million for the years ended December 31, 2020, 2019 and 2018, respectively.
24
Recent Accounting Pronouncements
See Note 3 (x) to our unaudited consolidated financial statements and Note 3 (x) and 3 (y) to our audited consolidated financial statements included in the Proxy Statement for recently adopted accounting pronouncements and recently issued accounting pronouncements not yet adopted as of the date of this Form 8-K.
Quantitative and Qualitative Disclosures about Market Risk
We are exposed to several market risks in our normal business activities. Market risk is the potential loss that may result from market changes associated with our power generation or with an existing or forecasted financial or commodity transaction. The types of market risks we are exposed to are commodity price risk, specifically electricity and renewable natural gas, interest rate risk, liquidity risk, and credit risk.
Interest Rate Risk
We are exposed to fluctuations in interest rates through our issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. Our risk management policies allow us to reduce interest rate exposure from variable rate debt obligations.
We enter into interest rate swaps, which are intended to economically hedge the risks associated with interest rates on non-recourse project level debt. For accounting purposes these interest swaps do not qualify for hedge accounting and are recorded at fair value on the consolidated balance sheet with changes in fair value recognized in profit or loss in the consolidated statement of comprehensive income.
We have long-term debt instruments that subject us to the risk of loss associated with movements in market interest rates.
Liquidity Risk
Liquidity risk arises from the general funding needs of our activities and in the management of our assets and liabilities.
Counterparty Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. We monitor and manage credit risk through credit policies that include: (i) an established credit approval process, and (ii) the use of credit mitigation measures such as prepayment arrangements or volumetric limits. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. We seek to mitigate counterparty risk by having a diversified portfolio of counterparties.
25