Bloom Energy Corp

1. Nature of Business, Liquidity and Basis of Presentation

Nature of Business

We design, manufacture, sell and, in certain cases, install solid oxide fuel cell systems (the “Energy Server systems”) for on-site power generation. Our Energy Server systems utilize innovative fuel cell technology and provide efficient energy generation with reduced operating costs and lower greenhouse gas emissions as compared to conventional fossil fuel generation. The solid oxide platform that powers our fuel cells can be used to create hydrogen with our Bloom Electrolyzer. In addition, the Energy Server systems allow us to provide energy solutions for customers, as our products are designed to work with existing carbon capture utilization and storage (“CCUS”) and combined heat and power (“CHP”) technologies. By generating power where it is consumed, our energy producing systems offer increased electrical reliability and improved energy security, while providing a path to energy independence. Our corporate headquarters are located in San Jose, California.

Liquidity

While we have generally incurred operating losses and negative cash flows from operations since our inception, we generated $92.0 million of positive cash flows from operations in fiscal year 2024. With the series of new debt offerings, debt extinguishments, and conversions to equity that we completed since 2021, we had $1,124.7 million and $4.1 million of total outstanding recourse and non-recourse debt, respectively, as of December 31, 2024, $114.4 million and $1,014.4 million of which was classified as short-term debt and long-term debt, respectively.

On October 23, 2021, we entered into the Securities Purchase Agreement (the “SPA”) with SK ecoplant Co., Ltd. (“SK ecoplant”, formerly known as SK Engineering & Construction Co., Ltd.) in connection with a strategic partnership. For more information on the strategic investment with SK ecoplant, please see Note 17 —SK ecoplant Strategic Investment and Note 11 —Related Party Transactions.

On August 19, 2022, we completed an underwritten public offering (the “Offering”), pursuant to which we issued and sold 13,000,000 shares of Class A common stock at the price of $26.00 per share. As a part of the Offering, the underwriters were provided a 30-day option to purchase an additional 1,950,000 shares of our Class A common stock at the same price, less underwriting discounts and commissions, which was exercised contemporaneously with the Offering. The aggregate net proceeds received by us from the Offering were $371.5 million after deducting underwriting discounts and commissions of $16.5 million and incremental costs directly attributable to the Offering of $0.7 million.

On May 29, 2024, we issued the 3% Green Convertible Senior Notes (the “3% Green Notes due June 2029”) in an aggregate principal amount of $402.5 million due June 2029, unless earlier repurchased, redeemed or converted, resulting in net cash proceeds of $389.7 million. On May 29, 2024, we used approximately $141.8 million of the net cash proceeds from this issuance to repurchase $115.0 million, or 50%, of the outstanding principal amount of our 2.5% Green Convertible Senior Notes due August 2025 (the “2.5% Green Notes”) in privately negotiated transactions. The repurchase amount equaled 122.6% of the principal amount repurchased, plus related accrued and unpaid interest. For more information on our recourse and non-recourse debt and purchase of Capped Calls, please see Note 7 —Outstanding Loans and Security Agreements.

Our future capital requirements depend on many factors, including our rate of revenue growth, the timing and extent of spending on research and development efforts and other business initiatives, the rate of growth in the volume of system builds and the need for additional working capital, the expansion of sales and marketing activities both in domestic and international markets, market acceptance of our products, our ability to secure financing for customer use of our products, the timing of installations and of inventory build in anticipation of future sales and installations, and overall economic conditions. In order to support and achieve our future growth plans, we may need or seek advantageously to obtain additional funding through equity or debt financing. Failure to obtain this financing on favorable terms or at all in future quarters may affect our financial position and results of operations, including our revenues and cash flows.

In the opinion of management, the combination of our cash and cash equivalents and cash flow to be generated by our operations is expected to be sufficient to meet our anticipated cash flow needs for at least the next 12 months from the date of issuance of this Annual Report on Form 10-K.

Inflation Reduction Act of 2022

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “IRA”). It contains provisions that have had a significant impact on the development and financing of clean energy projects in the U.S. However, President Trump has expressed skepticism about the IRA and clean energy projects, thus creating uncertainty about its future. The IRA includes expanded tax credits for projects across the Bloom product portfolio as well as for manufacturing of clean energy equipment. It also introduces new mechanisms for tax credit monetization and transferability. The IRA includes targeted incentives intended to encourage development in low-income communities, the use of domestically produced materials, and compliance with certain labor-related requirements. We believe that the programs and credits included in the IRA align well with our business model and could provide significant benefits for our projects.

The IRA introduces and updates several crediting mechanisms and incentive provisions that are relevant for us including:

•Section 48E— Clean Electricity Investment Credit, which starting December 31, 2024, replaces the previous investment tax credit framework for named clean energy technologies with a “tech neutral” framework anchored around the net carbon neutrality of energy generation from qualifying facilities. It provides incentives of up to 50% for qualifying energy property meeting domestic content and labor requirements.

•Section 45V— Credit for the Production of Clean Hydrogen, which provides a Production Tax Credit (the “PTC”) of up to $3 per kg of qualified clean hydrogen produced at qualified facilities in the US, including Bloom’s Electrolyzer projects. Bloom is also positioned to provide near-zero carbon power to natural gas based low carbon hydrogen facilities.

•Section 45Q— Credit for Carbon Oxide Sequestration, which provides up to a $60/tonne credit for carbon utilization and $85/tonne credit for geologic sequestration and can improve the cost effectiveness of Bloom’s carbon capture offerings.

•Section 45Z— Clean Fuel Production Credit, which provides a tax credit for the production of clean transportation fuels with lifecycle GHG emissions below certain levels. The credit can reach levels of up to $1.00/gallon for non-aviation fuel and $1.75/gallon for non-aviation fuel and is influenced by emissions associated with energy use including on-site power provided by Bloom.

•Section 48C— Qualified Advanced Energy Project, which provides an Investment Tax Credit (the “ITC”) through a competitive application process administered through the Department of Energy equal to 6% or 30% of the investment with respect to advanced energy projects

We believe that the programs and credits included in the IRA align well with our business model and could provide significant benefits with respect to incentivizing the purchase of our current product offerings and technologies. In particular, the IRA authorized a competitive process to apply for credits to expand or enhance manufacturing capacity under IRC 48C. On December 21, 2023, we submitted the application for qualifying advanced energy project credit allocation under Internal Revenue Code Section 48C(e) for the manufacturing facility in Fremont, California (the “Facility”). On March 29, 2024, we received notification from the Internal Revenue Service (the “IRS”) of the acceptance of our application for a Qualifying Advanced Energy Project Credit of up to $75.3 million. After a technical review of Bloom’s Section 48C(e) application, the Department of Energy provided a recommendation to the IRS to grant a $75.3 million credit allocation for the Facility. The approval is subject to satisfaction of the underlying certification requirements, including the prevailing wage and apprenticeship requirements, within two years from the date of the application acceptanceand potential clearance by the Office of Management and Budget due to President Trump’s executive order halting the disbursement of funds under the IRA.

The U.S. Treasury Department has issued implementation guidance, and we intend to engage with the new U.S. federal administration to understand how shifting policy priorities might impact the revised guidance or changes to the law itself. Current Section 48E guidance places Bloom Energy Server systems running on natural gas in a class of Combustion and Gasification facilities required to demonstrate net-zero emissions in the production of electricity. If the U.S. federal administration does not clarify key aspects of the guidance related to our unique technology, our projects will no longer be beneficiaries of the ITC. If the ITC is not extended for fuel cells, U.S. bookings, revenue and gross margins could be materially impacted in 2025 and beyond. Also, it is possible that the expiration of the ITC may have increased demand for ITC-compliant sales of our Energy Server systems in 2024 due to customer desire to secure ITC for their projects through safe harboring. However, if our customers or project-level investors prove reluctant to make sufficient cash outlays for purchases of Energy Server systems for future projects, our sales could be negatively impacted in future years.

Also, the PTC for qualified clean hydrogen and credit for carbon capture could result in increased demand for commercial solutions to hydrogen production technology and carbon capture, including our solid oxide fuel cell-based products.

At the time of IRA implementation in August 2022, some of our existing contracts contemplated price adjustments at the inception of the contract for the change in the ITC rate to 30%. As a result, we recognized $8.7 million in product revenue and $1.3 million in installation revenue for the year ended December 31, 2022, from such existing contracts, as a change in variable consideration estimate for Energy Server systems placed in service during the eligible periods under the IRA and which qualified for the 30% ITC rate. In fiscal years 2024 and 2023, all of our contract prices included the impact of the 30% ITC rate under the IRA provisions.

The IRA also creates certain bonus tax credits relevant to our products placed in service in fiscal years 2024 and 2023, available by satisfying domestic content criteria and/or other criteria if such products are located within an “energy community,” as defined by the IRA. In fiscal years 2024 and 2023 contracts that included price adjustments related to the domestic content bonus tax credit were evaluated as variable consideration and we estimated variable consideration by using the most likely amount method of meeting the IRA domestic content criteria. When recognizing revenue, we constrained the estimate of variable consideration to an amount that was not probable of a significant revenue reversal.

Basis of Presentation

We have prepared the consolidated financial statements included herein pursuant to the rules and regulations of the U. S. Securities and Exchange Commission (“SEC”), and as permitted by those rules, including all disclosures required by generally accepted accounting principles as applied in the U.S. (“U.S. GAAP”). Certain prior period amounts have been reclassified to conform to the current period presentation.

Principles of Consolidation

These consolidated financial statements reflect our accounts and operations and those of our subsidiaries in which we have a controlling financial interest. We use a qualitative approach in assessing the consolidation requirement for our variable interest entities (“VIEs”), which we refer to as tax equity partnerships (each such VIE, also referred to as our power purchase agreement, or PPA Entities) and a joint venture in the Republic of Korea (the “Korean JV”). This approach focuses on determining whether we have the power to direct those activities of the PPA Entities and the Korean JV that most significantly affect their economic performance and whether we have the obligation to absorb losses, or the right to receive benefits, which could potentially be significant to the PPA Entities and the Korean JV. For all periods presented, we have determined that we are the primary beneficiary in all of our operational PPA Entities and the Korean JV, as discussed in Note 10 —Portfolio Financings and Note 17 — SK ecoplant Strategic Investment, respectively. We evaluate our relationships with the PPA Entities and the Korean JV on an ongoing basis to ensure that we continue to be the primary beneficiary. In August 2023, we sold our last consolidated PPA Entity, 2015 ESA Project Company, LLC (“PPA V”), as a result of the PPA V Repowering of the Energy Server systems (see Note 10 —Portfolio Financings). All intercompany transactions and balances have been eliminated upon consolidation.

The sale of an operating company with a portfolio of the PPAs in which we do not have an equity interest is called a “Third-Party PPA.” We have determined that, although these entities are VIEs, we do not have the power to direct those activities of the Third-Party PPAs that most significantly affect their economic performance. We also do not have the obligation to absorb losses, or the right to receive benefits, which could potentially be significant to the Third-Party PPAs. Because we are not the primary beneficiary of these activities, we do not consolidate Third-Party PPAs.

Use of Estimates

The preparation of consolidated financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. The most significant estimates include the determination of the stand-alone selling price, valuation of financial instruments associated with the Amended SPA with SK ecoplant, inventory valuation, specifically excess and obsolescence provisions for obsolete or unsellable inventory and, in relation to property, plant and equipment (specifically Energy Server systems), assumptions relating to economic useful lives and impairment assessments.

Other accounting estimates include variable consideration relating to product performance guaranties, lease and non-lease components and related financing obligations such as incremental borrowing rates, estimated output, efficiency and residual value of our products, product performance warranties and guaranties and extended maintenance, derivative valuations, estimates relating to contractual indemnities provisions, estimates for income taxes and deferred tax asset valuation allowances, stock-based compensation expense, estimates of fair value of preferred stock and equity and non-equity items in relation to the SK ecoplant strategic investment, and financing obligation allocations in managed service transactions. In addition, certain of such estimates could require further judgment or modification and therefore carry a higher degree of variability and volatility. Actual results could differ materially from these estimates under different assumptions and conditions.

Concentration of Risk

Geographic Risk —The majority of our revenue and long-lived assets are attributable to operations in the U.S. for all periods presented. In addition to shipments in the U.S., we also ship our products to other countries, primarily to the Republic of Korea, Japan, India, and Taiwan (collectively referred to as the “Asia Pacific region”). In the years ended December 31, 2024, 2023 and 2022, total revenue in the U.S. was 74%,70% and 56%, respectively, of our total revenue.

Credit Risk —At December 31, 2024, three customers, the first of which is our related party (see Note 11 —Related Party Transactions), accounted for approximately 28%,28%, and 20% of accounts receivable. At December 31, 2023, one customer, who is our related party, accounted for approximately 74% of accounts receivable. To date, we have not experienced any material credit losses from these customers.

Customer Risk —During the year ended December 31, 2024, revenue from three customers, the first of which is our related party (see Note 11 —Related Party Transactions), accounted for approximately 23%,16% and 14% of our total revenue. During the year ended December 31, 2023, two customers, the first of which is our related party, represented approximately 37% and 26% of our total revenue. In the year ended December 31, 2022, revenue from two customers, the first of which is our related party, accounted for approximately 38% and 37% of our total revenue.

2. Summary of Significant Accounting Policies

Revenue Recognition

We primarily earn product and installation revenue from the sale and installation of our Energy Server systems and other products, service revenue by providing services under operations and maintenance services contracts, and electricity revenue by selling electricity to customers under PPAs and Managed Services Agreements. We offer our customers several ways to finance their use of our Energy Server systems. Customers, including some of our international channel providers and the Third-Party PPAs, may choose to purchase our Energy Server systems outright. Customers may also enter into contracts with us for the purchase of electricity generated by our Energy Server systems (i.e., Managed Services Agreements), which is then financed through one of our financing partners (i.e., Managed Services Financings). Finally, customers may purchase electricity through our PPA Entities (i.e., Portfolio Financings). For additional information, please see Part I, Item 7, Section Purchase and Financing Options.

Revenue Recognition under ASC 606 Revenue from Contracts with Customers

In applying Accounting Standards Codification (“ASC”) 606 revenue is recognized by following a five-step process:

1. Identify the contract(s) with a customer. Evidence of a contract generally consists of an agreement, or a purchase order issued pursuant to the terms and conditions of a distributor, reseller, purchase, use and maintenance agreement, maintenance services agreements or energy supply agreement.

2. Identify the performance obligations in the contract. Performance obligations are identified in our contracts and primarily include transferring control of our products, installation of the Energy Server systems, providing maintenance services and maintenance services renewal options which, in certain situations, provide customers with material rights.

3. Determine the transaction price. The purchase price stated in an agreed-upon purchase order or contract is generally representative of the transaction price. When determining the transaction price, we consider the effects of any variable consideration, which include performance guarantees that may be payable to our customers.

4. Allocate the transaction price to the performance obligations in the contract. The transaction price in a contract is allocated based upon the relative standalone selling price of each distinct performance obligation identified in the contract.

5. Recognize revenue when (or as) we satisfy a performance obligation. We satisfy performance obligations either over time or at a point in time as discussed in further detail below. Revenue is recognized at the time the related performance obligation is satisfied by transferring control of the promised products or services to a customer.

We sometimes combine contracts governing the sale and installation of our Energy Server systems with the related maintenance services contracts and account for them as a single contract at contract inception to the extent the contracts are with the same customer. These contracts are not combined when the customer for the sale and installation of the Energy Server systems is different to the maintenance services contract customer. We also assess whether any contract terms including default provisions, put or call options result in components of our contracts being accounted for as financing or leasing transactions outside of the scope of ASC 606.

Most of our contracts contain performance obligations with a combination of our products, installation and maintenance services. For these performance obligations, we allocate the total transaction price to each performance obligation based on the relative standalone selling price. Our maintenance services contracts are typically subject to renewal by customers on an annual basis. We assess these maintenance services renewal options at contract inception to determine whether they provide customers with material rights that give rise to separate performance obligations.

The total transaction price is determined based on the total consideration specified in the contract, including variable consideration in the form of a performance guaranty payment that represents potential amounts payable to customers. The expected value method is generally used when estimating variable consideration, which typically reduces the total transaction price due to the nature of the performance obligations to which the variable consideration relates. These estimates reflect our historical experience and current contractual requirements which cap the maximum amount that may be paid. The expected value method requires judgment and considers multiple factors that may vary over time depending upon the unique facts and circumstances related to each performance obligation. Depending on the facts and circumstances, a change in variable consideration estimate will either be accounted for at the contract level or using the portfolio method.

We exclude from the transaction price all taxes assessed by governmental authorities that are both (i) imposed on and concurrent with a specific revenue-producing transaction and (ii) collected from customers. Accordingly, such tax amounts are not included as a component of net sales or cost of sales. These tax amounts are recorded in the cost of electricity revenue, cost of service revenue, and general and administrative operating expenses.

We allocate the transaction price to each distinct performance obligation based on relative stand-alone selling prices. Given that we typically sell our products together with the related installation and maintenance services, standalone selling prices are not directly observable. We estimate standalone selling prices by using a cost-plus approach. Costs relating to our products include all direct and indirect manufacturing costs, applicable overhead costs and costs for normal production inefficiencies (i.e., variances). We then apply a margin to our products based on our Company’s pricing strategy. As our business offerings and eligibility for the ITC evolve over time, we may be required to modify the expected margin in subsequent periods and our revenue could be materially affected. Costs relating to installation include all direct and indirect installation costs. The margin we apply reflects our profit objectives relating to installation. Costs for maintenance services arrangements are estimated over the life of the maintenance contracts and include estimated future material costs and non-material costs. Material costs over the period of the service arrangement are impacted significantly by the longevity of the fuel cells themselves. We apply a lower margin to our total service costs than to our products as it best reflects our long-term service margin expectations and comparable historical industry service margins.

We generally recognize product and installation revenue at a point in time that our customers obtain control of our products. For certain instances, control of the installations is transferred to the customers over time, and the related revenue is recognized over time as the performance obligation is satisfied using the cost-to-cost (percentage-of-completion) method. We use an input measure of progress to determine the amount of revenue to be recognized during each reporting period. We recognize maintenance services revenue, including revenue associated with any related customer material rights, over time as we perform service maintenance activities.

Amounts billed to our customers for shipping and handling activities are considered contract fulfillment activities and not a separate performance obligation of the contract. Shipping and handling costs are recorded within the cost of revenue.

The following is a description of the principal activities from which we generate revenue. Our four revenue streams are classified as follows:

Product Revenue —All of our product revenue is generated from the sale of our products to direct purchase customers, including financing partners on the Third-Party PPAs and sale-and-leaseback transactions, and international channel providers.

We generally recognize product revenue from contracts with customers at the point that control is transferred to the customers. This occurs when we achieve customer acceptance, which depending on the contract terms is when the product is shipped and delivered to our customers, when the product is shipped and delivered and is physically ready for startup and commissioning (i.e., Mechanical Completion), or when the product is shipped and delivered and is turned on and operational (i.e., Commencement of Operations or “COO”), if required.

Under our traditional lease financing option, we sell our Energy Server systems through a direct sale to a financing partner who, in turn, lease the Energy Server systems to the customer under a lease agreement. With our sales to our international channel providers, our international channel providers typically sell the Energy Server systems to, or sometimes provide a PPA to, an end customer. In both traditional lease and international channel providers’ transactions, we contract directly with the end customer to provide extended maintenance services after the end of the standard warranty period. As a result, since the customer that purchases the server is a different and unrelated party to the customer that purchases extended warranty services, the product and maintenance services contract are not combined.

Installation Revenue —Nearly all of our installation revenue relates to the installation of the Energy Server systems sold to the customers as part of a direct purchase and to financing parties as part of a traditional lease or Portfolio Financings. Generally, we recognize installation revenue when the product is physically ready for startup and commissioning (i.e., Mechanical Completion), or when the product is turned on and operational (i.e., COO). For instances when control for installation services is transferred over time, we use an input measure of progress to determine the amount of revenue to recognize during each reporting period based on the costs incurred to satisfy the performance obligation.

Payments received from customers are recorded within deferred revenue and customer deposits in the consolidated balance sheets until control is transferred. The related cost of such product and installation is also deferred as a component of deferred cost of revenue in the consolidated balance sheets until control is transferred.

Service Revenue —Service revenue is generated from operations and maintenance agreements (“O&M Agreements”). As part of the first year of O&M services, we also monitor the operations of the underlying products and provide output and efficiency warranties and guaranties. We have determined that this standard first-year O&M services (including the warranties and guaranties) is a distinct performance obligation — being a promise to stand-ready to maintain our products when and if required during the first year following installation. We also sell to our customers extended annual maintenance services that effectively extend the standard first-year warranty coverage at the customer’s option. These customers generally have an option to renew or cancel the extended maintenance services on an annual basis and nearly every customer has renewed historically. Similar to the standard first-year O&M services, the optional extended annual maintenance services are considered a distinct performance obligation – being a promise to stand-ready to maintain the products when and if required during the renewal service year.

Given our customers’ renewal history, we anticipate that most of them will continue to renew their maintenance services agreements each year for the period of their expected use of the products. The contractual renewal price may be less than the stand-alone selling price of the maintenance services and consequently the contract renewal option may provide the customer with a material right. We estimate the standalone selling price for customer renewal options that give rise to material rights using the practical alternative by reference to optional maintenance services renewal periods expected to be provided and the corresponding expected consideration for these services. This reflects the fact that our additional performance obligations in any contractual renewal period are consistent with the services provided under the standard first-year warranty. Where we have determined that the customers have material rights as a result of their contract renewal option, we recognize that portion of the transaction price allocated to the material rights over the period in which such rights are exercised.

Payments from customers for the extended maintenance contracts are generally received at the beginning of each service year. Accordingly, the customer payment received is recorded as a customer deposit and revenue is recognized over the related service period as the services are performed.

Electricity Revenue —We sell electricity produced by Energy Server systems owned directly by us. Before the sale in August 2023 of our last consolidated PPA Entity, PPA V, we also were selling electricity produced by our Energy Server systems owned by our consolidated PPA Entities. Our PPA Entities purchased the Energy Server systems from us and sold electricity produced by these systems to customers through long-term PPAs. Customers were required to purchase all of the electricity produced by those Energy Server systems at agreed-upon rates over the course of the PPAs’ contractual term.

In addition, in certain Managed Services Financings pursuant to which we are party to a Managed Services Agreement with a customer in a sale-leaseback-sublease arrangement, we may recognize electricity revenue. We first determine whether the Energy Server systems under the sale-leaseback arrangement of a Managed Services Financing were “integral equipment.”

As the Energy Server systems were determined not to be integral equipment, we determined if the leaseback was classified as a financing lease or an operating lease.

Starting in the second half of fiscal year 2021, we completed several successful sale-and-leaseback transactions in which we transferred control of the Energy Server system to the financier and leased it back as an operating lease to provide electricity to the end customer.

In order for the transaction to meet the criteria for successful sale-leaseback accounting, control of the Energy Server systems must transfer to the financier, which requires, among other criteria, the leaseback to meet the criteria for an operating lease in accordance with ASC 842, Leases (“ASC 842”). Accordingly, for such transactions where control transfers and the leaseback is classified as an operating lease, the proceeds from the sale to the financier are recognized as revenue based on the fair value of the Energy Server systems sold and are allocated between product revenue and installation revenue based on the relative standalone selling prices.

We recognize an operating lease liability for the Energy Server systems leaseback obligation based on the present value of the future payments to the financier that are attributed to the Energy Server systems leaseback using our incremental borrowing rate (“IBR”). We also record an operating lease right-of-use asset, which is amortized over the term of the leaseback, and is included as a cost of electricity revenue on the consolidated statements of operations.

For certain sale-and-leaseback transactions, we receive proceeds from the financier in excess of the fair value of the Energy Server systems in order to finance our ongoing costs associated with the operation of the Energy Server systems during the term of the end customer agreement to provide electricity. Such proceeds are recognized as financing obligations.

We allocate payments we are obligated to make under the leaseback agreement with the financier between the operating lease liability and the financing obligation based on the proportion of the financing obligation to the total proceeds to be received.

We recognize revenue from the satisfaction of performance obligations under our PPAs and Managed Services Financings to provide electricity to our end customers as the electricity is provided over the term of the agreement in the amount invoiced, which reflects the amount of consideration to which we have the right to invoice, and which corresponds to the value transferred under such arrangements.

Modifications

Contract modifications are accounted for as separate contracts if the additional products and services are distinct and priced at stand-alone selling prices. If the additional products and services are distinct, but not priced at standalone selling prices, the modification is treated as a termination of the existing contract and the creation of a new contract. If the additional products and services are not distinct within the context of the contract, the modification is combined with the original contract and either an increase or decrease in revenue is recognized on the modification date.

Deferred Revenue

We recognize a contract liability (referred to as deferred revenue in our consolidated financial statements, excluding customer deposits) when we have an obligation to transfer products or services to a customer in advance of us satisfying a performance obligation and the contract liability is reduced as performance obligations are satisfied and revenue is recognized. The related costs are deferred as a component of deferred cost of revenue in the consolidated balance sheets. Prior to shipment of the product or the commencement of performance of maintenance services, any prepayment made by the customer is recorded as a customer deposit. Deferred revenue related to material rights for options to renew are recognized in revenue over the maintenance services period.

A description of the principal activities from which we recognize the cost of revenues associated with each of our revenue streams are classified as follows:

Cost of Product Revenue —Cost of product revenue consists of costs of our products that we sell to direct purchase, including financing partners on the Third-Party PPAs, international channel providers and traditional lease customers. It includes costs paid to our materials suppliers, direct labor, manufacturing and other overhead costs, shipping costs, provisions for excess and obsolete inventory and the depreciation costs of our equipment. For the Energy Server systems sold to customers pending installation, we provide warranty reserves as a part of product costs for the period from transfer of control of the Energy Server systems to the earlier of one year or Commencement of Operations.

Cost of Installation Revenue —Cost of installation revenue primarily consists of the costs to install our Energy Server systems that we sell to direct purchase, including financing partners on the Third-Party PPAs and traditional lease and successful sale-leaseback customers. It includes the cost of materials and service providers, personnel costs, shipping costs and allocated costs.

Cost of Service Revenue —Cost of service revenue consists of costs incurred under maintenance service contracts for all customers. It includes the cost of field replacement units, personnel costs for our customer support organization, certain allocated costs, and extended maintenance-related product repair and replacement costs.

Cost of Electricity Revenue —Cost of electricity revenue primarily consists of the depreciation of the cost of the Energy Server systems owned by us or the consolidated PPA Entities. The cost of electricity revenue is generally recognized over the term of the Managed Services Agreement or customer’s PPA contract. In August 2023, we sold our last consolidated PPA Entity, PPA V.

Revenue Recognized from Portfolio Financings Through the PPA Entities(See Note 10 —Portfolio Financings)

In 2010, we began selling our Energy Server systems to tax equity partnerships in which we held an equity interest as a managing member, or a PPA Entity. The investors in a PPA Entity contribute cash to the PPA Entity in exchange for an equity interest, which then allows the PPA Entity to purchase the Operating Company and the Energy Server systems.

The cash contributions held are classified as short-term or long-term restricted cash according to the terms of each PPA Entity’s governing documents. As we identified customers, the Operating Company entered into a PPA with the customer pursuant to which the customer agreed to purchase the power generated by one or more Energy Server systems at a specified rate per kilowatt hour for a specified term, which can range from 10 to 21 years. The Operating Company, wholly owned by the PPA Entity, typically entered into a maintenance services agreement with us following the first year of service to extend the standard one-year performance warranties and guaranties. This intercompany arrangement is eliminated on consolidation. Those PPAs that qualify as leases are classified as either sales-type leases or operating leases and those that do not qualify as leases are classified as tariff agreements or revenue arrangements with customers. For arrangements classified as operating leases, tariff agreements, or revenue arrangements with customers, income is recognized as contractual amounts are due when the electricity is generated and presented within electricity revenue on the consolidated statements of operations.

In August 2023, we sold our last consolidated PPA Entity, PPA V. Please refer to Note 10 —Portfolio Financings for details.

Sales-type Leases —Certain Portfolio Financings with the PPA Entities entered into prior to our adoption of ASC 842 qualified as sales-type leases in accordance with ASC 840, Leases (“ASC 840”). The classification for such arrangements were carried over and accounted for as sales-type leases under ASC 842.

In the fiscal year 2022 we sold PPA IIIa. Please refer to Note 10 —Portfolio Financings for details. We have not entered into any new Portfolio Financing arrangements through the PPA Entities during the last four years.

Operating Leases —Certain Portfolio Financings with the PPA Entities entered into prior to the adoption of ASC 842 that were deemed leases in substance but did not meet the criteria of sales-type leases or direct financing leases in accordance with ASC 840, were accounted for as operating leases. The classification for such arrangements was carried over and accounted for as operating leases under ASC 842. Revenue under these arrangements was recognized as electricity sales and service revenue and was provided to the customer at rates specified under the PPAs. During the years ended December 31, 2023, and 2022, revenue from electricity sales from these Portfolio Financings with the PPA Entities amounted to $14.3 million and $25.9 million, respectively. There wasno revenue from electricity sales from the Portfolio Financings with the PPA Entities during the year ended December 31, 2024. During the years ended December 31, 2023, and 2022, service revenue from operating leases amounted to $3.1 million, and $13.1 million, respectively. There wasno service revenue from operating leases during the year ended December 31, 2024. Service revenue related to sales-type leases was immaterial for the year ended December 31, 2022. There was no service revenue related to sales-type leases for the years ended December 31, 2024, and 2023.

Investment Tax Credits —Under our Portfolio Financings with PPA Entities, ITCs were primarily passed through to Equity Investors with approximately 1% to 10% of incentives received by us. These incentives were accounted for by using the flow-through method.

The ITC program has operational criteria for the first five years after the qualified equipment is placed in service. If the qualified energy property is disposed of or otherwise ceases to be investment credit property before the close of the five-year recapture period is fulfilled, it could result in a partial reduction of the federal tax incentives. No recapture occurred during the years ended December 31, 2024, 2023 and 2022.

In August 2022, the IRA was signed into law. The IRA includes numerous investments in climate protection, among them the extension and expansion of the ITC and the PTC, the addition of expanded tax credits for other technologies and for manufacturing clean energy equipment, as well as terms allowing parties to more easily monetize the tax credits. The IRA contains a two-tiered credit-amount structure for many applicable tax credits. Specifically, many of the credits have a lower base credit amount that can be increased up to five times if the taxpayer can satisfy applicable prevailing wage or apprenticeship requirements. The IRA also creates certain bonus tax credit amounts relevant to Bloom products placed in service in 2023 and 2024, available by satisfying domestic content criteria and/or locating within an “energy community,” as defined by the IRA. The IRA also creates tax credits for the production of hydrogen and carbon capture.

On August 16, 2022, the IRA enacted provisions to enable our Energy Server systems to be qualified for 30% or more ITCs. If a contract consideration subject to changes due to the underlying ITC rate assumption changes, we will consider such potential ITC benefit changes as a variable consideration and will generally estimate the variable consideration by using the most likely amount method. When recognizing revenue, we will constrain the estimate of variable consideration to an amount that is not probable of a significant revenue reversal. The ITC expired at the end of fiscal year 2024 with respect to fuel cells running on a non-zero carbon fuel.

Recapture of Federal Tax Incentives, Including the ITC

Until the ITC expired at the end of fiscal year 2024 with respect to fuel cells running on a non-zero carbon fuel, our Energy Server systems were eligible for federal ITCs that accrued to qualified property under Internal Revenue Code Section 48 when placed into service. However, the ITC program has operational criteria that extends for five years. If the energy property is disposed of or otherwise ceases to be qualified investment credit property before the close of the five-year recapture period is fulfilled, it could result in a partial reduction of the ITC. Our sale of Energy Server systems to the PPA Entities and pursuant to the Third-Party PPAs, in each case pursuant to Portfolio Financings, generates ITCs benefiting the third-party owners of the PPA Entities or tax equity partnerships (the tax equity partnership purchaser, an “Investment Company”) and, therefore, the third-party owners of the PPA Entities or Investment Companies, as the case may be, bear the risk of recapture if the assets placed in service do not meet the ITC operational criteria in the future.

Warranty Costs

We generally provide a manufacturer’s warranty to our products sold to our customers, international channel providers, and financing parties for up to one year following the date of COO of the Energy Server systems. This standard warranty covers defects in materials, workmanship and manufacturing or performance conditions under normal use and service conditions for the first year following COO. Such standard warranty is considered to be assurance-type warranty and consequently does not give rise to performance obligations under ASC 606 and are accounted for as warranty cost accruals under ASC 460— Guarantees.

We recognize warranty costs for those contracts that are considered to be assurance-type warranties and consequently do not give rise to performance obligations or for those maintenance service contracts that were previously in the scope of ASC 605-20-25, Separately Priced Extended Warranty and Product Maintenance Contracts.

In addition, as part of our standard warranty period and Managed Services Agreement obligations, we monitor the operations of the underlying systems and provide output and efficiency guaranties (collectively “product performance guaranties”). If the Energy Server systems run at a lower efficiency or power output than we committed under our performance warranty or guaranty, we will reimburse the customer for this underperformance. Our performance obligation includes ensuring the Energy Server systems operate at least at the efficiency and/or power output levels set forth in the customer agreement. Our aggregate reimbursement obligation for a performance guaranty for each customer is capped based on the purchase price of the underlying Energy Server systems. Product performance guaranty payments are accounted for as a reduction in service revenue. We accrue for performance guaranties based on the actual or estimated amounts (when actual data is not available) reimbursable at each reporting period and recognize the costs as a reduction to revenue.

Shipping and Handling Costs

We record costs related to shipping and handling in cost of product revenue, cost of installation revenue and cost of service as they are incurred.

Sales and Utility Taxes

We recognize revenue on a net basis for taxes charged to our customers and collected on behalf of the taxing authorities.

Sales Tax —Sales tax collected from customers is recorded as a liability, pending remittance to the taxing jurisdiction. Consequently, sales taxes have been excluded from revenues and costs. It is recognized as a liability until remitted to the applicable state.

Operating Expenses

Advertising and Promotion Costs —Expenses related to advertising and promotion of products are charged to sales and marketing expenses as incurred. Advertising and promotion expenses for the year ended December 31, 2024, was$1.4 million. We didnot incur any material advertising or promotion expenses during the years ended December 31, 2023, and 2022.

Research and Development —We conduct internally funded research and development activities to improve anticipated product performance and reduce product life-cycle costs. Research and development costs are expensed as incurred and include salaries and expenses related to employees conducting research and development and other costs.

Stock-Based Compensation —We account for time-based and performance-based stock options, restricted stock units (“RSUs”) and performance-based stock units (“PSUs”) awarded to employees and non-employee directors under the provisions of ASC 718, Compensation – Stock Compensation (“ASC 718”).

Stock-based compensation costs for time-based and performance-based stock options are measured using the Black-Scholes valuation model. The Black-Scholes valuation model uses as inputs the fair value of our common stock and assumptions we make for the volatility of our common stock, the expected term of the award, the risk-free interest rate for a period that approximates the expected term of the stock options and the expected dividend yield. In developing estimates used to calculate assumptions, we established the expected term for employee options as well as expected forfeiture rates based on the historical settlement experience and after giving consideration to vesting schedules. For options with a vesting condition tied to the attainment of service and market conditions, stock-based compensation costs are recognized using Monte Carlo simulations. Recognition of stock-based compensation expense associated with the performance-based stock options commences when the performance condition is considered probable of achievement, using management’s best estimates, which consider the inherent risk and uncertainty regarding the future outcomes of the milestones. Stock-based compensation costs are recorded net of estimated forfeitures such that expense is recorded only for those stock-based awards that are expected to vest. We typically record stock-based compensation costs for time-based and performance-based stock options under the straight-line attribution method over the requisite service period, which is generally the vesting term, which is generally three tofour years for options.

Stock-based compensation costs for RSUs and PSUs are measured based on the fair value of the underlying shares on the date of grant. We recognize the compensation cost for RSUs using a straight-line basis over the requisite service period of the RSUs, which is generally three tofour years. We recognize the compensation cost for PSUs over the expected performance period using the graded vesting method as the achievement of the milestones become probable, which is generallyone tothree years.

We also use the Black-Scholes valuation model to estimate the fair value of stock purchase rights under the Bloom Energy Corporation 2018 Employee Stock Purchase Plan (the “2018 ESPP”). The fair value of the 2018 ESPP purchase rights is recognized as an expense under the multiple options approach. Forfeitures are estimated at the time of grant and revised in subsequent periods, if necessary, if actual forfeitures differ from initial estimates.

Stock issued to grantees in our stock-based compensation is from authorized and previously unissued shares. Stock-based compensation costs are recorded in the consolidated statements of operations based on the employees’ respective functions. Stock-based compensation costs directly associated with the product manufacturing operations process are capitalized into inventory and deferred cost of revenue and expensed when the capitalized asset is used in the normal course of the sales or services process.

We record deferred tax assets for awards that result in deductions on our income tax returns, unless we cannot realize the deduction (i.e., we are in a net operating loss position), based on the amount of compensation cost recognized and our statutory tax rate.

Refer to Note 9 —Stock-Based Compensation and Employee Benefit Plansfor further discussion of our stock-based compensation arrangements.

Income Taxes

We account for income taxes using the liability method under ASC 740, Income Taxes (“ASC 740”). Under this method, deferred tax assets and liabilities are determined based on net operating loss carryforwards, research and development credit carryforwards and temporary differences resulting from the different treatment of items for tax and financial reporting purposes. Deferred items are measured using the enacted tax rates and laws that are expected to be in effect when the differences reverse. Additionally, we must assess the likelihood that deferred tax assets will be recovered as deductions from future taxable income. We have provided a full valuation allowance on our domestic deferred tax assets because we believe it is more likely than not that our deferred tax assets will not be realized.

We follow the accounting guidance in ASC 740, which requires a more-likely-than-not threshold for financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. We record a liability for the difference between the benefit recognized and measured pursuant to ASC 740-10 and the tax position taken or expected to be taken on our tax return. To the extent that the assessment of such tax positions changes, the change in estimate is recorded in the period in which the determination is made. We established reserves for tax-related uncertainties based on estimates of whether, and the extent to which additional taxes will be due. These reserves are established when we believe that certain positions might be challenged despite our belief that the tax return positions are fully supportable. The reserves are adjusted in light of changing facts and circumstances such as the outcome of a tax audit. The provision for income taxes includes the impact of reserve provisions and changes to reserves that are considered appropriate. We recognize interest and penalties related to unrecognized tax benefits in income tax expense.

Refer to Note 15 —Income Taxes for further discussion of our income tax expense.

Comprehensive Loss

Our comprehensive loss is comprised of net loss attributable to common stockholders, foreign currency translation adjustment, and comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest.

Fair Value Measurement

ASC 820, Fair Value Measurement (“ASC 820”), defines fair value, establishes a framework for measuring fair value under U.S. GAAP and enhances disclosures about fair value measurements. Fair value is defined under ASC 820 as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principle or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Valuation techniques used to measure fair value under ASC 820 must maximize the use of observable inputs and minimize the use of unobservable inputs. The guidance describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value:

Other Balance Sheet Components

Cash, Cash Equivalents, and Restricted Cash —Cash equivalents consist of highly liquid short-term investments with maturities of 90 days or less at the date of purchase.

Restricted cash is held as collateral to provide financial assurance that we will fulfill obligations and commitments primarily related to the Third-Party PPAs and Managed Services Agreements. Restricted cash also includes debt service reserves, maintenance service reserves and facility lease agreements. Restricted cash that is expected to be used within one year of the balance sheet date is classified as a current asset, whereas restricted cash expected to be used more than one year from the balance sheet date is classified as a non-current asset.

Derivatives —We account for our derivative instruments as a liability which are carried at fair value on the consolidated balance sheets. Changes in the fair value of those derivatives are recorded through earnings in the consolidated statements of operations, as they do not qualify neither as cash flow hedges, nor for hedge accounting.

Accounts Receivable —Accounts receivable primarily represent trade receivables from sales to customers recorded at amortized cost less allowance for credit losses. The allowance for credit losses reflects our best estimate about future losses over the contractual life of outstanding accounts receivable taking into consideration historical experience, specific allowances for known troubled accounts, other currently available information including customer financial condition, and both current and forecasted economic conditions.

Inventories —Inventories consist principally of raw materials, work-in-process and finished goods and are stated on a first-in, first-out basis at a lower of cost or net realizable value. We record inventory excess and obsolescence provisions for estimated obsolete or unsellable inventory, equal to the difference between the cost of inventory and estimated net realizable value based upon assumptions about market conditions and future demand for products generally expected to be utilized over the next 12 to 24 months, including product needed to fulfill our warranty obligations. If actual future demand for our products is less than currently forecasted, additional inventory provisions may be required. Once a provision is recorded, it is maintained until the product to which it relates is sold or otherwise disposed.

Property, Plant and Equipment —Property, plant and equipment, including leasehold improvements, are stated at cost less accumulated depreciation. The Energy Server systems are depreciated to their residual values over their useful economic lives which reflect consideration of the terms of their related PPA and tariff agreements. These useful lives are reassessed when there is an expected change in the use of the Energy Server systems. Leasehold improvements are depreciated over the shorter of the lease term or their estimated depreciable lives. Buildings are amortized over the shorter of the lease or property term or their estimated depreciable lives. Assets under construction are capitalized as costs are incurred and depreciation commences after the assets are put into service within their respective asset class.

Depreciation is calculated using the straight-line method over the estimated depreciable lives of the respective assets as follows:

• Lesser of 35 years or the term of the underlying land lease.

When assets are retired or disposed of, the assets and related accumulated depreciation and amortization are removed from our consolidated financial statements and the resulting gain or loss is reflected in the consolidated statements of operations.

Impairment of Long-Lived Assets — Our long-lived assets include property, plant and equipment and the Energy Server systems capitalized in connection with our Managed Services Financing Program, Portfolio Financings and other similar arrangements. The carrying amounts of our long-lived assets are periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying value of these assets may not be recoverable or that the useful life is shorter than originally estimated. Impairment charges for the year ended December 31, 2024, amounted to $87.0 million related to the termination of failed sale-and-leaseback transactions and were recorded in other income (expense), net on our consolidated statements of operations. Impairment charges for the year ended December 31, 2023, amounted to $123.7 million related to the PPA V Repowering and $2.3 million related to the termination of a failed sale-and-leaseback transaction, and were recorded in cost of electricity revenue and in other income (expense), net on our consolidated statements of operations, respectively. Impairment charges for the year ended December 31, 2022, amounted to $44.8 million and $64.0 million related to the PPA IIIa and PPA IV Repowerings, respectively, and were recorded in cost of electricity revenue on our consolidated statements of operations.

Allocation of Profits and Losses of Consolidated Entities to Noncontrolling Interests —We generally allocate profits and losses to noncontrolling interests under the hypothetical liquidation at book value (“HLBV”) method. The determination of equity in earnings under the HLBV method requires management to determine how proceeds, upon a hypothetical liquidation of the entity at book value, would be allocated between our investors. The noncontrolling interest balance is presented as a component of permanent equity in the consolidated balance sheets.

For income tax purposes, the Equity Investors of the PPA Entities receive a greater proportion of the share of losses and other income tax benefits. This includes the allocation of investment tax credits which are distributed to the Equity Investors through an Investment Company subsidiary of Bloom. Allocations are initially based on the terms specified in each respective partnership agreement until either a specific date or the Equity Investors’ targeted rate of return specified in the partnership agreement is met (the “flip” of the flip structure) whereupon the allocations change. In some cases, after the Equity Investors receive their contractual rate of return, we receive substantially all of the remaining value attributable to the long-term recurring customer payments and the other incentives. In August 2023, we sold our last consolidated PPA Entity being our VIE, PPA V, as a result of the PPA V Repowering of the Energy Server systems (see Note 10 —Portfolio Financings). As of December 31, 2024, and 2023, we had one VIE which we consolidate, Korean JV, which profit and loss are allocated to noncontrolling interests under the HLBV method.

Foreign Currency Considerations

Items included in the financial statements of each of the Company’s entities are measured using the currency of the primary economic environment in which the entity operates (the “functional currency”). The functional currency of the Company’s parent entity is the U.S. dollar.

The functional currencies of our foreign subsidiaries are local currencies. The functional currency of our joint venture in the Republic of Korea is the local currency, the South Korean won (“KRW”), since the joint venture is financially independent of its U.S. parent and the KRW is the currency in which the joint venture generates and expends cash. The assets and liabilities of these entities are translated at the rate of exchange at the balance sheet date. Revenue and expenses are translated at the weighted average rate of exchange during the period. For these entities, translation adjustments resulting from the process of translating the local currency financial statements into the U.S. dollars are included in other comprehensive loss. Translation adjustments attributable to noncontrolling interests are allocated to and reported as part of the noncontrolling interests in the consolidated financial statements.

Transactions made in a currency other than the functional currency are remeasured to the functional currency at exchange rates at the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies at the reporting date are remeasured to the functional currency at the exchange rate at that date and non-monetary assets and liabilities are measured at historical rates. Foreign currency transaction gains and losses are included as a component of other income (expense), net in our consolidated statements of operations.

The reporting currency for these consolidated financial statements is the U.S. dollar.

Accounting Guidance Not Yet Adopted

In November 2024, the FASB issued ASU 2024-04 Debt — Debt with Conversion and Other Options (Subtopic 470-20) (“ASU 2024-04”). ASU 2024-04 clarifies the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as an induced conversion. The standard is effective for annual reporting periods beginning after December 15, 2025, and interim periods within those annual reporting periods. Early adoption is permitted for all entities that have adopted the amendments in ASU 2020-06. We are currently evaluating this guidance, but do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

In November 2024, the FASB issued ASU 2024-03, Income Statement — Reporting Comprehensive Income — Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 is intended to enhance transparency of income statement disclosures primarily through additional disaggregation of relevant expense captions. The standard is effective for annual reporting periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027, with prospective or retrospective application permitted. We are currently evaluating this guidance, but do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

In March 2024, the FASB issued ASU 2024-02, Codification Improvements — Amendments to Remove References to the Concepts Statements(“ASU 2024-02”). This guidance is intended to remove references to various FASB Concepts Statements. The Board has a standing project on its agenda to address suggestions received from stakeholders on the Accounting Standards Codification and other incremental improvements to U.S. GAAP. This effort facilitates Codification updates for technical corrections such as conforming amendments, clarifications to guidance, simplifications to wording or the structure of guidance, and other minor improvements. The resulting amendments are referred to as Codification improvements. The amendments in ASU 2024-02 are not intended to result in significant accounting change for most entities. We are currently evaluating this guidance, but do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

In March 2024, the FASB issued ASU 2024-01, Compensation — Stock Compensation (Topic 718): Scope Application of Profits Interest and Similar Awards(“ASU 2024-01”). This guidance is intended to improve U.S. GAAP. by adding an illustrative example to demonstrate how an entity should apply the scope guidance in paragraph 718-10-15-3 to determine whether profits interest and similar awards (“profits interest awards”) should be accounted for in accordance with Topic 718, Compensation — Stock Compensation. The amendments in ASU 2024-01 are effective for annual periods beginning after December 15, 2024, and interim periods within those annual periods. The amendments in ASU 2024-01 should be applied either (1) retrospectively to all prior periods presented in the financial statements or (2) prospectively to profits interest and similar awards granted or modified on or after the date at which the entity first applies the amendments. We are currently evaluating this guidance, but do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

In August 2023, the FASB issued ASU 2023-05, Business Combinations — Joint Venture Formations (Subtopic 805-60): Recognition and Initial Measurement (“ASU 2023-05”), which addresses the accounting for contributions made to a joint venture. ASU 2023-05 requires joint ventures to measure all assets and liabilities upon formation at fair value. This guidance will be applied prospectively to all joint venture formations with a formation date on or after January 1, 2025. We have evaluated this guidance, and do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures(“ASU 2023-09”). ASU 2023-09 addresses investor requests for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. This guidance will be applied on a prospective basis and is effective for annual reporting periods in fiscal years beginning after December 15, 2024. Retrospective application is permitted. We are currently evaluating the potential impact, but we do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

Recent Accounting Pronouncements

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 requires disclosure of significant segment expenses that are regularly provided to the chief operating decision maker and included within the segment measure of profit or loss, and a description of how the chief operating decision maker utilizes segment operating profit or loss to assess segment performance. We adopted this accounting standard in fiscal year 2024. While the adoption has no impact on our financial statements, it has resulted in incremental disclosures within the footnotes to our consolidated financial statements.

There have been no significant changes in our reported financial position or results of operations and cash flows resulting from the adoption of new accounting pronouncements.

3. Revenue Recognition

Contract Balances

The following table provides information about accounts receivables, contract assets, customer deposits and deferred revenue from contracts with customers (in thousands):

Contract assets relate to contracts for which revenue is recognized upon transfer of control of performance obligations, but where billing milestones have not been reached. Contract liabilities are represented by deferred revenue. Customer deposits and deferred revenue include payments received from customers or invoiced amounts prior to transfer of goods or services.

Contract assets and contract liabilities are reported in a net position on an individual contract basis at the end of each reporting period. Contract assets are classified as current in the consolidated balance sheets when the milestones other than the passage of time, are expected to be complete and the customer is invoiced within one year of the balance sheet date, and as long-term when both the above-mentioned milestones are expected to be complete, and the customer is invoiced more than one year from the balance sheet date. Contract liabilities are classified as current in the consolidated balance sheets when the revenue recognition associated with the related customer payments and invoicing is expected to occur within one year of the balance sheet date and as long-term when the revenue recognition associated with the related customer payments and invoicing is expected to occur in more than one year from the balance sheet date.

In the fourth quarter of fiscal year 2024, our related party settled $223.9 million of accounts receivable (see Note 11 —Related Party Transactions).

The increase in contract assets of $103.8 million for the year ended December 31, 2024, was driven by the timing of achieving billing milestones.

The increase in customer deposits of $144.4 million for the year ended December 31, 2024, was driven by receipt of new deposits, partially offset by certain deposits becoming non-refundable.

Contract Assets

1 Included $9.6 million that have already been paid to customer’s customer for the year ended December 31, 2024. There wereno other adjustments for the year ended December 31, 2023.

Deferred Revenue

Deferred revenue activity during the years ended December 31, 2024, and 2023, consisted of the following (in thousands):

Deferred revenue is equivalent to the total transaction price allocated to the performance obligations that are unsatisfied, or partially unsatisfied, as of the end of the period. The primary component of deferred revenue at the end of the period consists of performance obligations relating to the provision of maintenance services under current contracts and future renewal periods. Some of these obligations provide customers with material rights over a period that we estimate to be largely commensurate with the period of their expected use of the associated products. As a result, we expect to recognize these amounts as revenue over a period of up to 21 years, predominantly on a relative stand-alone selling price basis that reflects the cost of providing these services. Deferred revenue also includes performance obligations relating to product acceptance and installation. A significant amount of this deferred revenue is reflected as additions and revenue recognized in the same 12-month period, and a portion of this deferred revenue is expected to be recognized beyond this 12-month period mainly due to deployment schedules.

We do not disclose the value of the unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.

Disaggregated Revenue

We disaggregate revenue from contracts with customers into four revenue categories: product, installation, service and electricity (in thousands):

4. Financial Instruments

Cash, Cash Equivalents, and Restricted Cash

The carrying values of cash, cash equivalents, and restricted cash approximate fair values and were as follows (in thousands):

Restricted cash consisted of the following (in thousands):

Factoring Arrangements

We sell certain customer trade receivables on a non-recourse basis under factoring arrangements with certain financial institutions. These transactions are accounted for as sales and cash proceeds are included in cash used in operating activities. We derecognized $184.2 million, $291.4 million, and $283.3 million of accounts receivable during the years ended December 31, 2024, 2023 and 2022, respectively.

The cost of factoring such accounts receivable on our consolidated statements of operations for the years ended December 31, 2024, 2023 and 2022, was $4.0 million, $5.5 million, and $4.0 million, respectively. The cost of factoring is recorded in general and administrative expenses.

5. Fair Value

Our accounting policy for the fair value measurement of cash equivalents is described in Note 2— Summary of Significant Accounting Policies.

Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis

The tables below set forth, by level, our financial assets and liabilities that are accounted for at fair value for the respective periods. The table does not include assets and liabilities that are measured at historical cost or any basis other than fair value (in thousands):

Money Market Funds —Money market funds are valued using quoted market prices for identical securities and are therefore classified as Level 1 financial assets.

Embedded Escalation Protection Plan Derivative Liability in Sales Contracts —We estimate the fair value of the embedded EPP derivatives in certain sales contracts using a Monte Carlo simulation model, which considers various potential electricity price curves over the sales contracts’ terms. We use historical grid prices and available forecasts of future electricity prices to estimate future electricity prices. We have classified these derivatives as Level 3 financial liability.

The changes in the Level 3 financial liabilities during the years ended December 31, 2024, 2023 and 2022, were as follows (in thousands):

To estimate the liabilities related to the EPP contracts, an option pricing method was implemented through a Monte Carlo simulation, which considers various potential electricity price forward curves over the sales contracts’ terms. We use historical grid prices and available forecasts to estimate future electricity prices. The grid pricing EPP guarantees that we provided in some of our sales arrangements represent an embedded derivative, with the initial value accounted for as a reduction in product revenue and any changes, reevaluated quarterly, in the fair market value of the derivative recorded in (Loss) gain on revaluation of embedded derivatives.

The unobservable inputs were simulated based on the available values for avoided cost and cost of electricity as calculated for December 31, 2024, and 2023, using an expected growth rate of 7% over the contracts’ life and volatility of 15%. The estimated growth rate and volatility were estimated based on the historical tariff changes for the period 2008 to 2024. Avoided cost is the transmission and distribution cost expressed in dollars per kilowatt hours avoided in the given year of the contract, calculated using the billing rates of the effective utility tariff applied during the year to the host account for which usage is offset by the generator. If the billing rates within the utility tariff change during the measurement period, the average amount of charge for each rate shall be weighted by the number of effective months for each amount.

The inputs listed above would have had a direct impact on the fair values of the EPP derivatives if they were adjusted. Generally, a decrease in electric grid prices would result in an increase in the estimated fair value of our EPP derivative liabilities.

For the years ended December 31, 2024, 2023 and 2022, we recorded the fair value of the embedded EPP derivatives with no material unrealized gains or losses in either of the three years ended December 31, 2024, 2023 and 2022, in our consolidated statements of operations. The fair value of these derivatives was $5.1 million and $4.4 million as of December 31, 2024, and 2023, respectively.

In June 2023, according to an EPP agreement with one of our customers, we paid $3.2 million, which was recorded as a reduction to our balance of embedded EPP derivative liability as of December 31, 2023.

Financial Assets and Liabilities Not Measured at Fair Value on a Recurring Basis

Debt Instruments —The term loans and convertible senior notes are based on rates currently offered for instruments with similar maturities and terms (Level 2). The following table presents the estimated fair values and carrying values of debt instruments (in thousands):

6. Balance Sheet Components

Inventories

The components of inventory consist of the following (in thousands):

The inventory reserves were $15.9 million and $18.7 million as of December 31, 2024, and 2023, respectively.

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consist of the following (in thousands):

Property, Plant and Equipment, Net

Property, plant and equipment, net, consists of the following (in thousands):

Depreciation expense related to property, plant and equipment was $53.0 million, $62.6 million and $61.6 million for the years ended December 31, 2024, 2023, and 2022, respectively.

Depreciation expense for property, plant and equipment under operating leases by PPA V (sold in August 2023) was $10.9 million for the year ended December 31, 2023. Depreciation expense for property, plant and equipment under operating leases by PPA V, PPA IV (sold in November 2022), and PPA IIIa (sold in June 2022) was $12.1 million for the year ended December 31, 2022. There wasno depreciation expense for such assets for the year ended December 31, 2024.

PPA IIIa Repowering

In June 2022, we started a project (the “PPA IIIa Repowering”) to replace 9.8 megawatts of the Energy Server systems (the “old PPA IIIa Energy Servers”) at PPA IIIa Investment Company and Operating Company (“PPA IIIa”) with current generation Energy Server systems (the “new PPA IIIa Energy Servers”). The replacement was completed in the fourth quarter of fiscal year 2022. See Note 10— Portfolio Financingsfor additional information.

PPA IV Repowering

In November 2022, we started a project (the “PPA IV Repowering”) to replace 19.3 megawatts of the Energy Server systems (the “old PPA IV Energy Servers”) at PPA IV Investment Company and Operating Company (“PPA IV”) with current generation Energy Server systems (the “new PPA IV Energy Servers”). The replacement was completed in the first quarter of fiscal year 2024. See Note 10— Portfolio Financingsfor additional information.

PPA V Repowering

In August 2023, we started a project (the “PPA V Repowering”) to replace 37.1 megawatts of the Energy Server systems (the “old PPA V Energy Servers”) at PPA V with current generation Energy Server systems (the “new PPA V Energy Servers”). The replacement was completed in the first quarter of fiscal year 2024. See Note 10— Portfolio Financings for additional information.

Assets Buyout and Repowering

In fiscal years 2024 and 2023, we terminated certain of our legacy managed services agreements, previously recorded as failed sale and lease-back transactions upon inception and bought back the old Energy Server systems from the respective legacy financiers. Total cost of Energy Server systems bought back was $144.1 million and $3.3 million, respectively. See Note 8— Leases for failed sale and lease-back transactions termination accounting.

Title for certain Energy Server systems bought back in December 2024, was simultaneously transferred to a Bloom-owned special purpose vehicle (the “SPV”, “New Project Company”), subsequently sold to the new financier. Upon sale, we entered into the EPC Agreement and the O&M Agreement with the New Project Company. See Note 10— Portfolio Financings for additional information.

Other Long-Term Assets

Other long-term assets consist of the following (in thousands):

Accrued Warranty and Product Performance Liabilities

Accrued warranty and product performance liabilities consist of the following (in thousands):

Changes in the product warranty and product performance liabilities were as follows (in thousands):

Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consist of the following (in thousands):

Preferred Stock

As of December 31, 2024, and 2023, we had 20,000,000 shares of preferred stock authorized.13,491,701 of these shares (the “Second Tranche Shares”) were designated as the Series B redeemable convertible preferred stock, par value $0.0001 per share (the “Series B RCPS”) and were converted to Class A common stock as of September 23, 2023, as a result of the SK ecoplant Second Tranche Closing. For additional information, please see Note 17— SK ecoplant Strategic Investment.

The preferred stock had $0.0001 par value. There wereno shares of preferred stock issued and outstanding as of December 31, 2024, and December 31, 2023.

Conversion of Class B Common Stock

On July 27, 2023, in accordance with our Restated Certificate of Incorporation, each share of our Class B common stock entitled toten votes per share automatically converted intoone share of our Class A common stock entitled toone vote per share.

7. Outstanding Loans and Security Agreements

The following is a summary of our debt as of December 31, 2024 (in thousands, except percentage data):

The following is a summary of our debt as of December 31, 2023 (in thousands, except percentage data):

Recourse debt refers to debt that we have an obligation to pay. Non-recourse debt refers to debt that is recourse to only our subsidiary, Korean JV. The differences between the unpaid principal balances and the net carrying values apply to the deferred financing costs. We and all of our subsidiaries were in compliance with all financial covenants as of December 31, 2024, and December 31, 2023.

Recourse Debt Facilities

3% Green Convertible Senior Notes due June 2029

On May 29, 2024, we issued the 3% Green Notes due June 2029 in an aggregate principal amount of $402.5 million due on June 1, 2029, unless earlier repurchased, redeemed or converted, less an initial purchasers’ discount of $12.1 million and other issuance costs of $0.7 million (together, the “3% Green Notes due June 2029 Transaction Costs”), resulting in net proceeds of $389.7 million. The 3% Green Notes due June 2029 were issued pursuant to, and are governed by, an indenture, dated as of May 29, 2024, between us and U.S. Bank Trust Company, National Association, as Trustee (the “3% Green Notes due June 2029 Indenture”), in private placements to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933, as amended (the “Securities Act”).

Pursuant to the purchase agreement among the Company and the representatives of the initial purchasers of the 3% Green Notes due June 2029, the Company granted the initial purchasers an option to purchase up to an additional $52.5 million aggregate principal amount of the 3% Green Notes due June 2029 (the “3% Green Notes due June 2029 Greenshoe Option”). The 3% Green Notes due June 2029 issued on May 29, 2024, included $52.5 million aggregate principal amount pursuant to the full exercise by the initial purchasers of the 3% Green Notes due June 2029 Greenshoe Option.

The 3% Green Notes due June 2029 are senior, unsecured obligations accruing interest at a rate of 3% per annum, payable semi-annually in arrears on June 1 and December 1 of each year, beginning on December 1, 2024.

We may not redeem the 3% Green Notes due June 2029 prior to June 7, 2027, subject to a partial redemption limitation. We may elect to redeem, at face value, all or any portion of the 3% Green Notes due June 2029 at any time, and from time to time, on or after June 7, 2027, and on or before the twenty-first scheduled trading day immediately before the maturity date, provided the share price for our Class A common stock exceeds 130% of the conversion price at redemption.

Before March 1, 2029, the noteholders have the right to convert their 3% Green Notes due June 2029 only upon the occurrence of certain events, including satisfaction of a condition relating to the closing price of our common stock (the “3% Green Notes due June 2029 Closing Price Condition”) or the trading price of the 3% Green Notes due June 2029 (the “3% Green Notes due June 2029 Trading Price Condition”), a redemption event, or other specified corporate events. If the 3% Green Notes due June 2029 Closing Price Condition is met on at least 20 (whether or not consecutive) of the last 30 consecutive trading days in any calendar quarter, and only during such calendar quarter, the noteholders may convert their 3% Green Notes due June 2029 at any time during the immediately following quarter, commencing after the calendar quarter ending on September 30, 2024, subject to the partial redemption limitation. The 3% Green Notes due June 2029 Closing Price Condition was not met during the three months ended September 30, 2024, and accordingly, the noteholders could not convert their 3% Green Notes due June 2029 during the quarter ended December 31, 2024.

Subject to the 3% Green Notes due June 2029 Trading Price Condition, the noteholders may convert their 3% Green Notes due June 2029 during thefive business days immediately after anyfive consecutive trading day period in which the trading price per $1,000 principal amount of the 3% Green Notes due June 2029, as determined following a request by a holder of the 3% Green Notes due June 2029, for each day of that period is less than 98% of the product of the closing price of our common stock and the then applicable conversion rate. From and after March 1, 2029, the noteholders may convert their 3% Green Notes due June 2029 at any time at their election until the close of business on the second scheduled trading day immediately before the maturity date. Should the noteholders elect to convert their 3% Green Notes due June 2029, we may elect to settle the conversion by paying or delivering, as applicable, cash, shares of our Class A common stock, $0.0001 par value per share, or a combination thereof, at our election.

The initial conversion rate is 47.9795 shares of Class A common stock per $1,000 principal amount of notes, which represents an initial conversion price of approximately $20.84 per share of Class A common stock. The conversion rate and conversion price are subject to customary adjustments upon the occurrence of certain events. Also, we may increase the conversion rate at any time if our Board of Directors determines it is in the best interests of the Company or to avoid or diminish income tax to holders of common stock. In addition, if certain corporate events that constitute a Make-Whole Fundamental Change, as defined below, occur, then the conversion rate applicable to the conversion of the 3% Green Notes due June 2029 will, in certain circumstances, increase by up to 15.5932 shares of Class A common stock per $1,000 principal amount of notes for a specified period of time. At December 31, 2024, the maximum number of shares into which the 3% Green Notes due June 2029 could have been potentially converted if the conversion features were triggered was 25,588,011 shares of Class A common stock.

According to the 3% Green Notes due June 2029 Indenture, a Make-Whole Fundamental Change means (i) a Fundamental Change, that includes certain change-of-control events relating to us, certain business combination transactions involving us and certain delisting events with respect to our Class A common stock, or (ii) the sending of a redemption notice with respect to the 3% Green Notes due June 2029.

The 3% Green Notes due June 2029 contain certain customary provisions relating to the occurrence of Events of Default, as defined in the 3% Green Notes due June 2029 Indenture. If an Event of Default involving bankruptcy, insolvency or reorganization events with respect to us occurs, then the principal amount of, and all accrued and unpaid interest on, all of the 3% Green Notes due June 2029 then outstanding will immediately become due and payable without any further action or notice by any person. However, notwithstanding the foregoing, we may elect, at our option, that the sole remedy for an Event of Default relating to certain failures by us to comply with certain reporting covenants in the 3% Green Notes due June 2029 Indenture consists exclusively of the right of the noteholders to receive special interest on the 3% Green Notes due June 2029 for up to 180 days at a specified rate per annum not exceeding 0.5% on the principal amount of the 3% Green Notes due June 2029.

The 3% Green Notes due June 2029 Transaction Costs were recorded as debt issuance costs and presented a reduction to the 3% Green Notes due June 2029 on our consolidated balance sheets and are amortized to interest expense at an effective interest rate of 3.8%.

Total interest expense recognized related to the 3% Green Notes due June 2029 for the year ended December 31, 2024, was $8.6 million, and was comprised of (i) contractual interest expense and (ii) amortization of the initial purchasers’ discount and other issuance costs of $7.1 million and $1.5 million, respectively. We have not recognized any special interest expense related to the 3% Green Notes due June 2029 to date. The amount of unamortized debt issuance costs as of December 31, 2024, was $11.3 million.

Although the 3% Green Notes due June 2029 contain embedded conversion features, we account for the 3% Green Notes due June 2029 in its entirety as a liability. As of December 31, 2024, the net carrying value of the 3% Green Notes due June 2029 was classified as a long-term liability in our consolidated balance sheets.

3% Green Convertible Senior Notes due June 2028

On May 16, 2023, we issued the 3% Green Convertible Senior Notes (the “3% Green Notes due June 2028”) in an aggregate principal amount of $632.5 million due on June 1, 2028, unless earlier repurchased, redeemed or converted, less an initial purchasers’ discount of $15.8 million and other issuance costs of $3.9 million (together, the “3% Green Notes due June 2028 Transaction Costs”), resulting in net proceeds of $612.8 million. The 3% Green Notes due June 2028 were issued pursuant to, and are governed by, an indenture, dated as of May 16, 2023, between us and U.S. Bank Trust Company, National Association, as Trustee (the “3% Green Notes due June 2028 Indenture”), in private placements to qualified institutional buyers pursuant to the Securities Act.

Pursuant to the purchase agreement among us and the representatives of the initial purchasers of the 3% Green Notes due June 2028, we granted the initial purchasers an option to purchase up to an additional $82.5 million aggregate principal amount of the 3% Green Notes due June 2028 (the “3% Green Notes due June 2028 Greenshoe Option”). The 3% Green Notes due June 2028 issued on May 16, 2023, included $82.5 million aggregate principal amount pursuant to the full exercise by the initial purchasers of the 3% Green Notes due June 2028 Greenshoe Option.

The 3% Green Notes due June 2028 are senior, unsecured obligations accruing interest at a rate of 3% per annum, payable semi-annually in arrears on June 1 and December 1 of each year, beginning on December 1, 2023.

We may not redeem the 3% Green Notes due June 2028 prior to June 5, 2026, subject to a partial redemption limitation. We may elect to redeem, at face value, all or any portion of the 3% Green Notes due June 2028 at any time, and from time to time, on or after June 5, 2026, and on or before the forty-sixth scheduled trading day immediately before the maturity date, provided the share price for our Class A common stock exceeds 130% of the conversion price at redemption.

Before March 1, 2028, the noteholders have the right to convert their 3% Green Notes due June 2028 only upon the occurrence of certain events, including satisfaction of a condition relating to the closing price of our common stock (the “3% Green Notes due June 2028 Closing Price Condition”) or the trading price of the 3% Green Notes due June 2028 (the “3% Green Notes due June 2028 Trading Price Condition”), a redemption event, or other specified corporate events. If the 3% Green Notes due June 2028 Closing Price Condition is met on at least 20 (whether or not consecutive) of the last 30 consecutive trading days in any calendar quarter, and only during such calendar quarter, the noteholders may convert their 3% Green Notes due June 2028 at any time during the immediately following quarter, commencing after the calendar quarter ending on September 30, 2023, subject to partial redemption limitation. The 3% Green Notes due June 2028 Closing Price Condition was not met during the three months ended September 30, 2024, and accordingly, the noteholders could not convert their 3% Green Notes due June 2028 during the quarter ended December 31, 2024.

Subject to the 3% Green Notes due June 2028 Trading Price Condition, the noteholders may convert their 3% Green Notes due June 2028 during thefive business days immediately after anyfive consecutive trading day period in which the trading price per $1,000 principal amount of the 3% Green Notes, as determined following a request by a holder of the 3% Green Notes due June 2028, for each day of that period is less than 98% of the product of the closing price of our common stock and the then applicable conversion rate. From and after March 1, 2028, the noteholders may convert their 3% Green Notes due June 2028 at any time at their election until the close of business on the second scheduled trading day immediately before the maturity date. Should the noteholders elect to convert their 3% Green Notes due June 2028, we may elect to settle the conversion by paying or delivering, as applicable, cash, shares of our Class A common stock, $0.0001 par value per share, or a combination thereof, at our election.

The initial conversion rate is 53.0427 shares of Class A common stock per $1,000 principal amount of notes, which represents an initial conversion price of approximately $18.85 per share of Class A common stock. The conversion rate and conversion price are subject to customary adjustments upon the occurrence of certain events. Also, we may increase the conversion rate at any time if our Board of Directors determines it is in the best interests of the Company or to avoid or diminish income tax to holders of common stock. In addition, if certain corporate events that constitute a Make-Whole Fundamental Change, as defined below, occur, then the conversion rate applicable to the conversion of the 3% Green Notes due June 2028 may, in certain circumstances, be increased by up to 22.5430 shares of Class A common stock per $1,000 principal amount of notes for a specified period of time. On December 31, 2024, the maximum number of shares into which the 3% Green Notes due June 2028 could have been potentially converted if the conversion features were triggered was 47,807,955 shares of Class A common stock.

According to the 3% Green Notes due June 2028 Indenture, a Make-Whole Fundamental Change means (i) a Fundamental Change, that includes certain change-of-control events relating to us, certain business combination transactions involving us and certain delisting events with respect to our Class A common stock, or (ii) the sending of a redemption notice with respect to the 3% Green Notes due June 2028.

The 3% Green Notes due June 2028 contain certain customary provisions relating to the occurrence of Events of Default, as defined in the 3% Green Notes due June 2028 Indenture. If an Event of Default involving bankruptcy, insolvency or reorganization events with respect to us occurs, then the principal amount of, and all accrued and unpaid interest on, all of the 3% Green Notes due June 2028 then outstanding will immediately become due and payable without any further action or notice by any person. However, notwithstanding the foregoing, we may elect, at our option, that the sole remedy for an Event of Default relating to certain failures by us to comply with certain reporting covenants in the 3% Green Notes due June 2028 Indenture consists exclusively of the right of the noteholders to receive special interest on the 3% Green Notes due June 2028 for up to 180 days at a specified rate per annum not exceeding 0.50% on the principal amount of the 3% Green Notes due June 2028.

The 3% Green Notes due June 2028 Transaction Costs were recorded as debt issuance costs and presented a reduction to the 3% Green Notes due June 2028 on our consolidated balance sheets and are amortized to interest expense at an effective interest rate of 3.8%.

The total interest expense recognized related to the 3% Green Notes due June 2028 for the years ended December 31, 2024, and 2023, was $22.9 million and $14.4 million, respectively and was comprised of contractual interest expense of $19.0 million and $12.0 million and amortization of the initial purchasers’ discount and other issuance costs of $3.9 million and $2.4 million, respectively. We have not recognized any special interest expense related to the 3% Green Notes to date. The amount of unamortized debt issuance costs as of December 31, 2024, and 2023, was $13.4 million and $17.3 million.

Although the 3% Green Notes due June 2028 contain embedded conversion features, we account for the 3% Green Notes due June 2028 in its entirety as a liability. As of December 31, 2024, and 2023, the net carrying value of the 3% Green Notes due June 2028 was classified as a long-term liability in our consolidated balance sheets.

Capped Calls

On May 11, 2023, in connection with the pricing of the 3% Green Notes due June 2028, and on May 15, 2023, in connection with initial purchasers’ exercise of the 3% Green Notes due June 2028 Greenshoe Option, we entered into privately negotiated capped call transactions (the “Capped Calls”) with certain counterparties (the “Option Counterparties”). The Capped Calls cover, subject to customary anti-dilution adjustments substantially similar to those applicable to the 3% Green Notes due June 2028, the aggregate number of shares of our Class A common stock that initially underlie the 3% Green Notes due June 2028, and are expected generally to reduce potential dilution to holders of our common stock upon any conversion of the 3% Green Notes due June 2028 and at our election (subject to certain conditions), offset any cash payments we would be required to make in excess of the principal amount of converted 3% Green Notes due June 2028.

The Capped Calls expire on June 1, 2028, and are exercisable only at maturity, but may be early terminated in various circumstances, including if the 3% Green Notes due June 2028 are early converted or repurchased. The default settlement method for the Capped Calls is net share settlement. However, we may elect to settle the Capped Calls in cash.

The Capped Calls have an initial strike price of approximately $18.85 per share of Class A common stock, subject to certain adjustments. The strike price of $18.85 corresponds to the initial conversion price of the 3% Green Notes due June 2028. The number of shares underlying the Capped Calls is 33,549,508 shares of Class A common stock. The cap price of the

Capped Calls is initially $26.46 per share of Class A common stock, which represents a premium of 100% over the last reported sale price of our common stock on May 11, 2023.

The Capped Calls are freestanding financial instruments. We used a portion of the proceeds from the issuance of the 3% Green Notes due June 2028 to pay for the Capped Calls’ premium. As the Capped Calls meet certain accounting criteria, they are recorded in stockholders’ equity and are not accounted for as derivatives. The cost of $54.5 million incurred to purchase the Capped Calls was recorded as a reduction to additional paid-in capital on our consolidated balance sheets and will not be remeasured.

2.5% Green Convertible Senior Notes due August 2025

In August 2020, we issued the 2.5% Green Convertible Senior Notes due August 2025 (the “2.5% Green Notes”) in an aggregate principal amount of $230.0 million, unless earlier repurchased, redeemed or converted, less an initial purchaser’s discount of $6.9 million and other issuance costs of $3.0 million (together, the “2.5% Green Notes Transaction Costs”), resulting in net proceeds of $220.1 million. The 2.5% Green Notes were issued pursuant to, and are governed by, an indenture, dated as of August 11, 2020, between us and U.S. Bank National Association, as trustee (the “2.5% Green Notes Indenture”),

The 2.5% Green Notes are senior, unsecured obligations accruing interest at a rate of 2.5% per annum, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on February 15, 2021.

We may elect to redeem, at face value, all or any portion of the 2.5% Green Notes at any time on or after August 21, 2023, and on or before the twenty-sixth trading day immediately before the maturity date, provided certain conditions are met. In December 2024, the optional redemption feature of the 2.5% Green Notes was satisfied as the last reported sale price of the Company’s common stock exceeded 130% of the conversion price on each of at least 20 trading days (whether or not consecutive) during the 30 consecutive trading day period. However, we did not issue a notice of redemption as of December 31, 2024.

Before May 15, 2025, the noteholders have the right to convert their 2.5% Green Notes only upon the occurrence of certain events, including satisfaction of a condition relating to the closing price of our common stock (the “2.5% Green Notes Closing Price Condition”). If the 2.5% Green Notes Closing Price Condition is met on at least 20 of the last 30 consecutive trading days in any quarter, the noteholders may convert their 2.5% Green Notes at any time during the immediately following quarter. The 2.5% Green Notes Closing Price Condition was not met during the three months ended September 30, 2024, and accordingly, the noteholders could not convert their 2.5% Green Notes during the quarter ended December 31, 2024. From and after May 15, 2025, the noteholders may convert their 2.5% Green Notes at any time at their election until the close of business on the second trading day immediately before the maturity date. Should the noteholders elect to convert their 2.5% Green Notes, we may elect to settle the conversion by paying or delivering, as applicable, cash, shares of our Class A common stock or a combination thereof.

The initial conversion rate is 61.6808 shares of Class A common stock per $1,000 principal amount of notes, which represents an initial conversion price of approximately $16.21 per share of Class A common stock. The conversion rate and conversion price are subject to customary adjustments upon the occurrence of certain events. In addition, if certain corporate events that constitute a “Make-Whole Fundamental Change”, as defined in the 2.5% Green Notes Indenture, occur, the conversion rate applicable to the conversion of the 2.5% Green Notes may, in certain circumstances, be increased by up to 15.4202 shares of Class A common stock per $1,000 principal amount of notes for a specified period of time.

On May 29, 2024, we used approximately $141.8 million of the net proceeds from the 3% Green Notes due June 2029 offering to repurchase $115.0 million of the outstanding principal amount of our 2.5% Green Notes in privately negotiated transactions. Half of the original principal balance, $115.0 million of the 2.5% Green Notes, was called and repurchased at 122.6% during the second quarter of fiscal year 2024. The 22.6% premium of $26.0 million and unpaid accrued interest of $0.8 million related to the repurchased amount were included in the final payment to the noteholders. As a result of the partial repurchase of the 2.5% Green Notes, we recognized a loss on extinguishment of debt of $27.2 million.

On December 31, 2024, and 2023, the maximum number of shares into which the 2.5% Green Notes could have been potentially converted if the conversion features were triggered was 8,866,615 and 17,733,230 shares of Class A common stock, respectively.

The 2.5% Green Notes Transaction Costs were recorded as debt issuance costs and presented a reduction to the 2.5% Green Notes on our consolidated balance sheets and were amortized to interest expense at an effective interest rate of 3.5% before the partial repurchase. The effective interest rate of the 2.5% Green Notes after the partial repurchase was 3.3%.

The total interest expense recognized related to the 2.5% Green Notes for the years ended December 31, 2024, 2023, and 2022, was $5.5 million, $7.7 million, and $7.7 million, respectively, and was comprised of contractual interest expense of $4.1 million, $5.7 million, and $5.7 million and amortization of issuance costs of $1.4 million, $2.0 million, and $2.0 million, respectively. We have not recognized any special interest expense related to the 2.5% Green Notes to date. The amount of unamortized debt issuance costs as of December 31, 2024, and 2023, was $0.6 million and $3.2 million, respectively.

Although the 2.5% Green Notes contain embedded conversion features, we account for the 2.5% Green Notes in its entirety as a liability. As of December 31, 2024, and 2023, the net carrying value of the 2.5% Green Notes was classified as a short-term liability and as a long-term liability in our consolidated balance sheets, respectively.

Non-recourse Debt Facilities

4.6% Term Loans due April 2026 and October 2026

On April 11, 2023, and October 5, 2023, Korean JV entered into three-year $1.5 million andthree-year $3.1 million credit agreements with SK ecoplant, respectively, to help fund its working capital. Both loans bear a fixed interest rate of 4.6% payable upon maturity along with the principal. Neither loan requires us to maintain a debt service reserve.

Repayment Schedule and Interest Expense

The following table presents details of our outstanding loan principal repayment schedule as of December 31, 2024 (in thousands):

Interest expense of $62.6 million, $108.3 million, and $53.5 million for the years ended December 31, 2024, 2023 and 2022, respectively, was recorded in interest expense on the consolidated statements of operations. Interest expense for the year ended December 31, 2023, included $52.8 million as a result of the SK ecoplant Second Tranche Closing. For additional information, please see Note 17 —SK ecoplant Strategic Investment.

8. Leases

Facilities, Energy Server Systems, and Vehicles

We lease most of our facilities, the Energy Server systems, and vehicles under operating and finance leases that expire at various dates through November 2037. We lease various manufacturing facilities in California and Delaware. We lease additional office space as field offices in the U.S. and around the world including in India, Germany, Ireland, Japan, the Republic of Korea, Taiwan, China, and Singapore.

Some of the lease arrangements have free rent periods or escalating rent payment provisions. We recognize lease cost under such arrangements on a straight-line basis over the life of the leases. For the years ended December 31, 2024, 2023 and 2022, rent expenses for all occupied facilities were $22.4 million, $23.0 million and $21.4 million, respectively.

At inception of the contract, we assess whether a contract is a lease based on whether the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Lease classification, measurement, and recognition are determined at lease commencement, which is the date the underlying asset is available for use by us. The accounting classification of a lease is based on whether the arrangement is effectively a financed purchase of the underlying asset (financing lease) or not (operating lease). Our operating leases are comprised primarily of leases for facilities, the Energy Server systems, office buildings, and vehicles, and our financing leases are comprised primarily of vehicles.

Our leases have lease terms ranging from less than 1 year to 15 years, some of which include options to extend the leases. The lease term is the non-cancelable period of the lease and includes options to extend the lease when it is reasonably certain that an option will be exercised.

Lease liabilities are measured at the lease commencement date as the present value of future lease payments. Lease right-of-use assets are measured as the lease liability plus unamortized initial direct costs and prepaid (accrued) lease payments less unamortized balance lease incentives received. In measuring the present value of the future lease payments, the discount rate for the lease is the rate implicit in the lease unless that rate cannot be readily determined. In that case, the lessee is required to use its IBR. In computing our lease liabilities, we use the IBR based on the information available on the commencement date using an estimate of company-specific rate in the U.S. on a collateralized basis and consistent with the lease term for each lease. The lease term is the non-cancelable period of the lease and includes options to extend or terminate the lease when it is reasonably certain that an option will be exercised.

Operating and financing lease right-of-use assets and lease liabilities as of December 31, 2024, and 2023, were as follows (in thousands):

1 These assets primarily include leases for facilities, the Energy Server systems, and vehicles.

2 Net of accumulated amortization.

3 These assets primarily include leases for vehicles.

4 Included in property, plant and equipment, net in the consolidated balance sheets.

5 Included in accrued expenses and other current liabilities in the consolidated balance sheets.

6 Included in other long-term liabilities in the consolidated balance sheets.

The components of our lease costs for the years ended December 31, 2024, 2023 and 2022, were as follows (in thousands):

Weighted average remaining lease terms and discount rates for our leases as of December 31, 2024, and 2023, were as follows:

Future lease payments under lease agreements as of December 31, 2024, were as follows (in thousands):

Managed Services Financing

Certain of our customers enter into Managed Services Financing to finance their lease of Bloom Energy Server systems. Customer arrangements under Managed Services Financing entered into after January 1, 2020, do not contain a lease under ASC 842 and are accounted for under ASC 606 as revenue arrangements.

Lease agreements under our Managed Services Financing include non-cancellable lease terms, during which terms the majority of our investment in the Energy Server systems under lease are typically recovered. We mitigate the remaining residual value risk of the Energy Server systems through provision of maintenance on the Energy Server systems during the lease term and through insurance which proceeds are payable in the event of theft, loss, damage, or destruction.

Our Managed Services Financing with financiers that result in failed sale-and-leaseback transactions are accounted for as financing transactions. Payments received from the financier are recognized as financing obligations in our consolidated balance sheets. Proceeds from the financiers in excess of fair value of the Energy Server systems under successful sale-and-leaseback transactions are also accounted for as financing obligations. These financing obligations are included in each agreement’s contract value and are recognized as short-term or long-term financing obligations based on the estimated payment dates. The lease agreements expire on various dates through 2034. For successful sale-and-leaseback transactions, we record operating lease right-of-use assets and operating lease liabilities and record operating lease expenses over the lease term.

We recognized $9.4 million, $28.7 million, and $20.4 million of product revenue, and $4.5 million, $8.4 million, and $11.3 million of installation revenue from successful sale-and-leaseback transactions for the years ended December 31, 2024, 2023, and 2022, respectively. The recognized operating lease expense from successful sale-and-leaseback transactions for the years ended December 31, 2024, 2023 and 2022, was $12.8 million, $9.7 million, and $5.6 million, respectively.

Operating lease right-of-use assets from successful sale-and-leaseback transactions as of December 31, 2024, and 2023, were $47.2 million and $47.6 million, respectively. Operating lease liability from successful sale-and-leaseback transactions as of December 31, 2024, and 2023, was $50.4 million and $50.1 million, including long-term operating lease liability of $42.1 million and $43.7 million, respectively. Financing obligations from successful sale-and-leaseback transactions as of December 31, 2024, and 2023, were $11.0 million and $10.9 million, including long-term financing obligations of $8.9 million and $9.3 million, respectively.

At December 31, 2024, future lease payments under the Managed Services Agreements financing obligations were as follows (in thousands):

The total financing obligations, as reflected in our consolidated balance sheets, were $255.8 million and $444.8 million as of December 31, 2024, and 2023, respectively. We expect the difference between these obligations and the principal obligations in the table above to be offset against the carrying value of the related Energy Server systems at the end of the lease and the remainder recognized as either a net gain or net loss at that point. For the years ended December 31, 2024, and 2023, we recognized a $17.4 million net gain and $0.4 million net loss on failed sale-and-leaseback transactions in other income (expense), net on our consolidated statements of operations, respectively.

9. Stock-Based Compensation and Employee Benefit Plans

Share-based grants are designed to reward employees for their long-term contributions to us and provide incentives for them to remain with us.

2012 Equity Incentive Plan

Our 2012 Equity Incentive Plan (the “2012 Plan”) was approved in August 2012. The 2012 Plan provided for the grant of incentive stock options, non-statutory stock options, stock appreciation rights and RSUs, all of which may be granted to employees, including officers, and to non-employee directors and consultants except we may grant incentive stock options only to employees.

Grants under the 2012 Plan generally vest ratably over afour-year period from the vesting commencement date and expireten years from the grant date. As of December 31, 2024, and 2023, stock options to purchase of 3,691,919 and 4,511,074 shares of Class A common stock were outstanding with a weighted average exercise price of $27.38 and $27.28 per share, respectively, andno shares were available for future grant. The 2012 Equity Incentive Plan has been canceled but continues to govern outstanding option grants under the 2012 Plan.

2018 Equity Incentive Plan

The 2018 Equity Incentive Plan (the “2018 Plan”) was approved in April 2018. The 2018 Plan became effective upon our initial public offering (“IPO”) and serves as the successor to the 2012 Plan. The 2018 Plan authorizes the award of stock options, restricted stock awards, stock appreciation rights, RSUs, PSUs and stock bonuses. The 2018 Plan provides for the grant of awards to employees, directors, consultants, independent contractors and advisors provided the consultants, independent contractors, directors and advisors render services not in connection with the offer and sale of securities in a capital-raising transaction. The exercise price of stock options is at least equal to the fair market value of Class A common stock on the date of grant. Grants under the 2018 Plan generally vest ratably over three orfour years from the vesting commencement date and expireten years from the grant date.

The 2018 Plan allows for an annual increase on January 1, of each of 2019 through 2028, by the lesser of (a) four percent (4%) of the number of Class A common stock and common stock equivalents (including options, RSUs, warrants and preferred stock on an as-converted basis) issued and outstanding on each December 31 immediately prior to the date of increase, and (b) such number of shares determined by the Board of Directors.

As of December 31, 2024, and 2023, stock options to purchase 3,740,902 and 2,736,550 shares of Class A common stock were outstanding, respectively, with a weighted average exercise price of $10.14 and $10.42 per share, respectively. As of December 31, 2024, and 2023,12,896,465 and 9,887,706 RSUs and PSUs that may be settled for Class A common stock, which were granted pursuant to the 2018 Plan, respectively, were outstanding. As of December 31, 2024, and 2023, we had 35,263,475 and 32,877,906 shares reserved for issuance under the 2018 Plan, respectively.

Stock-Based Compensation Expense

The following table summarizes the components of stock-based compensation expense in the consolidated statements of operations (in thousands):

During the years ended December 31, 2024, 2023 and 2022, stock-based compensation expense capitalized on inventory and deferred cost of goods sold was immaterial.

Stock Option and Stock Award Activity

Stock Options

The following table summarizes the stock option activity under our stock plans during the reporting period:

During the years ended December 31, 2024, 2023 and 2022, we recognized $3.2 million, $0.4 million and $7.1 million of stock-based compensation costs for stock options, respectively.

During the year ended December 31, 2024, we granted 1,364,348 stock options, including 1,135,000 stock options granted to certain executives to purchase shares of common stock that contain certain performance-based vesting criteria related to corporate milestones (the “performance-based stock options”). The performance-based stock options were granted “at-the-money” and have a term of 10 years. The performance-based stock options vest based over athree-year or afour-year requisite service period. We didnot grant options in the years ended December 31, 2023, and 2022.

We used the following weighted-average assumptions in applying the Black-Scholes valuation model for determination of the stock options valuation:

During the years ended December 31, 2024, 2023 and 2022, the intrinsic value of stock options exercised was $2.1 million, $3.6 million and $3.8 million, respectively.

As of December 31, 2024, and 2023, we had unrecognized compensation costs related to unvested stock options of $7.2 million and $0.1 million, respectively. This cost is expected to be recognized over the remaining weighted-average period of 2.1 years and 0.3 years, respectively. Cash received from stock options exercised totaled $2.0 million, $3.6 million and $3.7 million and for the years ended December 31, 2024, 2023 and 2022, respectively.

Stock Awards

A summary of our stock awards activity and related information is as follows:

The estimated fair value of RSUs and PSUs is based on the fair value of our Class A common stock on the date of grant. For the years ended December 31, 2024, 2023 and 2022, we recognized $70.1 million, $71.2 million and $89.4 million of stock-based compensation costs for stock awards, respectively.

As of December 31, 2024, and 2023, we had $161.8 million and $113.5 million of unrecognized stock-based compensation cost related to unvested stock awards, expected to be recognized over a weighted average period of 2.2 years and 2.0 years, respectively.

Executive Awards

Fiscal Year 2024

On December 18, 2024, the Company’s board of directors cancelled 1,150,000 PSU awards from the equity package the Chief Executive Officer (the “CEO”) received on May 12, 2021 (the “2021 PSUs”), under the 2018 Plan. The 2021 PSUs were cancelled due to the lack of their retention value and the change in the Company’s strategic goals. Also, on December 18, 2024, the Company’s board of directors granted the CEO replacement awards that included (1) a front-loaded three-year equity award consisting of: (i)1,500,000 PSU awards and (ii)500,000 RSU awards (the “2025 Equity Package”), and (2) a one-time award of 600,000 PSU awards (the “One-Time Grant”, and together with the 2025 Equity Package, the “Replacement Awards”).

The 2025 Equity Package RSU awards have time-based vesting schedule ofthree years and started vesting on December 18, 2024. The performance criteria under the 2025 Equity Package PSU awards are equally weighted between product revenue growth and adjusted product gross margin. The CEO is eligible to receive up to 300% of the target PSUs under the 2025 Equity Package, which is intended to provide a meaningful retention incentive for the CEO over the next several years. The 2025 Equity Package PSUs have athree-year cliff performance vesting period.

The One-Time Grant consists oftwo awards: (i) a grant of 300,000 PSUs that fully vested on December 18, 2024, and (ii) a grant of 300,000 PSUs that will be earned and vest following the Compensation and Organizational Development Committee’s certification that the CEO has achieved specific, objective criteria tied to strategic priorities prior to December 31, 2027. The maximum amount of shares the CEO can earn under the One-Time Grant is 600,000 shares of our Class A common stock.

The cancellation of the 2021 PSUs accompanied by the concurrent grant of the Replacement Awards was accounted for as a modification of the terms of the cancelled award according to the ASC 718. On December 18, 2024, the Company determined the incremental compensation cost of $42.4 million measured as the excess of the fair value of the Replacement Awards over the fair value of the cancelled award immediately before the terms were modified. These compensation costs will be recognized over the requisite service period of the Replacement Awards. The total fair value of the Replacement Awards of $57.6 million measured at the date of a cancellation and replacement consisted of (1) the grant-date fair value of the original award for which the service has already been rendered and is expected to be rendered at that date, and (2) the incremental cost resulting from the cancellation and replacement. For the year ended December 31, 2024, we recognized $7.6 million of compensation costs related to the Replacement Awards.

On March 1, 2024, the Company granted RSUs, PSUs, time-based and performance-based stock option awards to certain executive staff; on May 6, 2024, the Company granted RSUs and PSUs to new executive hires, including our new Chief Financial Officer; and on August 29, 2024, the Company granted additional performance-based stock option awards to our Chief Commercial Officer (collectively, the “2024 Executive Awards”), pursuant to the 2018 Plan.

The RSUs have time-based vesting schedules that range fromtwo tofour years, and started vesting on February 15, 2024 (May 15, 2024, for new hires).

The time-based stock options started vesting on February 15, 2024, and shall vest over three years. The PSUs have vesting schedules that range fromone tothree years. The performance-based stock options have vesting schedules that range from three tofour years. Both the PSUs and the performance-based stock options have a threshold target for vesting of 50% of the number of awards, a target for 100% of earned awards and a maximum of 150% of granted awards earned, for each of the performance periods.

The PSUs and performance-based stock options will vest based on a combination of time and achievement against performance metrics targets assuming continued employment and service through each vesting date. Stock-based compensation costs associated with the 2024 Executive Awards are recognized over the service period as we evaluate the probability of the achievement of the performance conditions. As of December 31, 2024, the unamortized compensation expense for the RSUs, the PSUs, the time-based and the performance-based stock options per the 2024 Executive Awards and the Replacement Awards was $66.8 million.

Fiscal Year 2023

On February 15, 2023, and July 11, 2023, the Company granted RSU and PSU awards (the “2023 Executive Awards”) to certain executive staff pursuant to the 2018 Plan. The RSU awards have time-based vesting schedules, started vesting on February 15, 2023, and shall vest over athree-year period. The PSU awards which started vesting on February 15, 2023, have either athree-year orone-year cliff vesting period, and the PSU awards which started vesting on July 11, 2023, cliff vest on February 15, 2024. The PSU awards will vest based on a combination of time and achievement against performance metrics targets assuming continued employment and service through each vesting date. Stock-based compensation costs associated with the 2023 Executive Awards are recognized over the service period as we evaluate the probability of the achievement of the performance conditions. As of December 31, 2024, and 2023, the unamortized compensation expense for the 2023 Executive Awards was $1.8 million and $7.0 million, respectively.

Fiscal Year 2022

In 2022, the Company granted RSU and PSU awards (the “2022 Executive Awards”) to certain executive staff, including our CEO, pursuant to the 2018 Plan. The RSUs have time-based vesting schedules. The PSUs consist ofthree vesting tranches during 2023-2025 with an annual vesting schedule based on the attainment of performance conditions related to fiscal year 2022 and assuming continued employment and service through each vesting date. Stock-based compensation costs associated with the 2022 Executive Awards are recognized over the service period. As of December 31, 2024, and 2023, the unamortized compensation expense for the 2022 Executive Awards was $1.0 million and $6.2 million, respectively. Actual compensation expense is determined by the attained performance condition of the PSUs in fiscal year 2022.

Fiscal Year 2021

In 2021, the Company granted RSU and PSU awards (the “2021 Executive Awards”) to certain executive staff, other than our Chief Executive Officer, pursuant to the 2018 Plan. The RSUs have time-based vesting schedules. The PSUs consist of annual vesting tranches based on the attainment of performance conditions and assuming continued employment and service through each vesting date. Stock-based compensation costs associated with the 2021 Executive Awards are recognized over the service period as we evaluate the probability of the achievement of the performance conditions.

In 2021, the Company also granted RSU and PSU awards to our CEO pursuant to the 2018 Plan. The RSUs will vest in equal annual installments over five years from the grant date. A portion of the PSUs can be earned based on achieving certain financial performance goals and another portion can be earned based upon achieving certain progressive stock price hurdles. Any shares issued under the PSU awards will be subject to atwo-year post-vest holding period in which the award holder will be restricted from selling any shares (net of shares settled for taxes).

Actual compensation expense is dependent on the performance of the PSUs that vest based upon a performance condition. We estimated the fair value of the PSUs that vest based on a market condition on the date of grant using a Monte

Carlo simulation with the following assumptions: (i) expected volatility of 71.2%, (ii) risk-free interest rate of 1.6%, and (iii)no expected dividend yield.

On December 18, 2024, the Company cancelled 1,150,000 PSU awards from the 2021 Executive Awards and replaced them with the 2025 Equity Package.

As of December 31, 2024, and 2023, the unamortized compensation expense for 2021 Executive Awards was $3.7 million, and $8.2 million, respectively.

The following table presents the stock activity and the total number of shares available for grant under our stock plans:

2018 Employee Stock Purchase Plan

In April 2018, we adopted the 2018 ESPP. The 2018 ESPP became effective upon our IPO in July 2018. The 2018 ESPP is intended to qualify under Section 423 of the Internal Revenue Code. The aggregate number of our shares that may be issued over the term of our ESPP is 33,333,333 Class A common stock. A total of 3,333,333 shares of our Class A common stock were initially reserved for issuance under the plan. The number of shares reserved for issuance under the 2018 ESPP will increase automatically on the 1st day of January of each of the first nine years following the first offering date by the number of shares equal to one percent (1%) of the total number of Class A common stock, Class B common stock (automatically converted to Class A common stock on July 27, 2023) and common stock equivalents (including options, RSUs, warrants and preferred stock on an as converted basis) issued and outstanding on the immediately preceding December 31 (rounded down to the nearest whole share); provided, that the Board of Directors or the Compensation Committee may in its sole discretion reduce the amount of the increase in any particular year.

The 2018 ESPP allows eligible employees to purchase shares, subject to purchase limits of 2,500 shares during eachsix-month period or $25,000 worth of stock for each calendar year, of our Class A common stock through payroll deductions at a price per share equal to 85% of the lesser of the fair market value of our Class A common stock (i) on the first trading day of the applicable offering date and (ii) the last trading day of each purchase date.

During the years ended December 31, 2024, 2023 and 2022, we recognized $5.9 million, $15.5 million and $16.2 million of stock-based compensation costs for the 2018 ESPP, respectively. We issued 1,049,955,875,695 and 759,744 shares in the years ended December 31, 2024, 2023 and 2022, respectively. During the years ended December 31, 2024, 2023 and 2022, we added an additional 2,418,528,2,239,563 and 12,055,792 shares, respectively. There were 16,573,157 and 15,204,584 shares available for issuance as of December 31, 2024, and 2023, respectively.

As of December 31, 2024, and 2023, we had $5.9 million and $8.8 million of unrecognized stock-based compensation costs, expected to be recognized over a weighted average period of 0.8 years and 0.8 years, respectively.

We used the following weighted-average assumptions in applying the Black-Scholes valuation model for determination of the 2018 ESPP share valuation: