1015-00001 · Graymont Brothers Inc · Registration Statement

mda-section.docx DOCUMENT Capital Markets

124 / 167 ← → ✕

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of the financial condition and results of operations of Calloway-Briggs Renewables Inc. should be read in conjunction with our audited consolidated financial statements for the fiscal years ended December 31, 2019, December 31, 2020, and December 31, 2021, and our unaudited condensed consolidated interim financial data for the three months ended March 31, 2022, and the notes thereto, each of which is included elsewhere in this prospectus. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in forward-looking statements as a result of various factors, including, but not limited to, those set forth under "Risk Factors" and elsewhere in this prospectus. See "Cautionary Note Regarding Forward-Looking Statements."

1. Overview

1.1 Company Description

Calloway-Briggs Renewables Inc. ("CBR," the "Company," "we," "us," or "our") is a Delaware-incorporated, Texas-headquartered developer, owner, and operator of utility-scale solar photovoltaic ("solar PV"), onshore wind, and battery energy storage systems ("BESS") projects across the United States. Our corporate headquarters are located at 4200 Ridgeline Parkway, Suite 1100, Austin, Texas 78746. The Company was founded in 2014 by Garrett Calloway, who serves as our Chairman and Chief Executive Officer, and Elaine Briggs, who serves as our President, Development. Since our founding, we have grown from a single early-stage development project to one of the leading independent renewable energy platforms in the southwestern United States.

As of the date of this prospectus, we employ approximately 1,240 full-time employees across our corporate headquarters, regional development offices, and project sites. Our operations currently span five states: Texas, New Mexico, Arizona, California, and Oklahoma. We have built a vertically integrated platform that encompasses the full lifecycle of renewable energy projects, from site identification, permitting, and development through construction management, long-term ownership, and ongoing operations.

Our mission is to accelerate the transition to clean energy by delivering reliable, low-cost renewable electricity to utilities and commercial and industrial ("C&I") customers across the United States. We believe our track record of successful project development and execution, our deep market expertise in our core geographies, and our diversified portfolio across solar, wind, and storage technologies position us well for continued growth.

1.2 Business Overview and Operating Portfolio

As of March 31, 2022, we had approximately 3.8 gigawatts ("GW") of operating renewable energy capacity across 22 projects, making us one of the largest independent power producers focused on renewable energy in the southwestern United States. In addition to our operating portfolio, we had approximately 1.4 GW of capacity under active construction, including the Mesquite Wind project (420 MW, expected commercial operation date ("COD") in the third quarter of 2022), the Cimarron Solar project (350 MW, expected COD in the first quarter of 2023), and other smaller-scale projects in various stages of construction. Beyond our operating and construction-stage assets, we maintain a robust development pipeline of approximately 6.2 GW of potential future projects at various stages of development, providing us with significant long-term growth visibility.

Our technology mix encompasses three core renewable energy technologies: utility-scale solar PV, onshore wind, and lithium-ion battery energy storage. We believe this diversification across technologies provides several benefits, including the ability to optimize our portfolio for varying weather and resource conditions, capture complementary generation profiles (solar generation peaks during daytime hours and summer months, while wind generation often peaks during nighttime hours and spring/fall seasons), and address the growing need for dispatchable energy storage to support grid reliability.

Our revenue model is primarily driven by long-term power purchase agreements ("PPAs") with investment-grade utility and C&I offtakers. These PPAs typically have terms ranging from 10 to 25 years and provide contracted, predictable cash flows that underpin our ability to finance projects and service our debt obligations. Our contracted revenue base is supplemented by merchant energy sales at prevailing wholesale market prices and ancillary services revenue, which includes income from frequency regulation, voltage support, and capacity market participation, particularly from our Brazos Storage battery project. For the fiscal year ended December 31, 2021, approximately 84% of our total revenue was derived from long-term PPAs, with the remainder attributable to merchant energy sales and ancillary services.

1.3 Key Operating Projects

The following table summarizes certain information regarding our key operating, construction-stage, and development-stage projects as of the date of this prospectus:

The projects listed above represent a substantial portion of our operating capacity and substantially all of our construction-stage and near-term development pipeline. In addition to these key projects, we own and operate 17 other smaller operating projects with aggregate capacity of approximately 1.9 GW, and our broader development pipeline includes additional projects at earlier stages of development that are not individually identified above.

1.4 Corporate Structure

We operate through a holding company structure designed to provide organizational clarity, facilitate project-level financing, and isolate project risks. The following summarizes our material corporate entities:

• Calloway-Briggs Renewables Inc. — Delaware C-corporation; the parent entity and issuer in this offering.

• CBR Holdings LLC — Delaware limited liability company; intermediate holding company, 100% owned by CBR.

• Calloway-Briggs Operating Company LLC ("CB Operating") — Texas limited liability company; 100% owned by CBR Holdings; serves as the primary operating entity and direct or indirect parent of our project-level entities.

• Project-level special-purpose vehicles ("SPVs") — Each held 100% by CB Operating, including: Solaris West Solar LLC, Red Mesa Wind Energy LLC, Painted Rock Solar LLC, Pronghorn Wind LLC, Brazos Energy Storage LLC, Mesquite Wind Holdings LLC, and Cimarron Solar Development LLC. Each SPV holds the assets, contracts, and permits associated with the applicable project and serves as the borrower under any project-finance debt facilities.

• CBR Development Co. LLC — Texas limited liability company; 100% owned by CB Operating; serves as our pipeline development entity, holding early-stage development assets and incurring pre-construction development costs.

This structure allows us to ring-fence project-level obligations and limit recourse to the parent company, while providing flexibility for tax-equity financing and other project-level capital structures. For a more detailed description of our corporate structure, see "Organizational Structure" elsewhere in this prospectus.

1.5 Pre-IPO Ownership and Proposed Offering

Prior to this offering, our equity ownership is held by the following principal constituencies:

• Pinnacle Vista Capital Partners III, LP ("Pinnacle Vista"), a private equity fund focused on energy infrastructure, holds approximately 62% of our outstanding common stock. Pinnacle Vista made its initial investment of $385 million in the Company in 2017, followed by a follow-on equity contribution of $120 million in 2019 to fund our expansion into battery storage and additional development projects.

• Founders and Management hold approximately 24% of our outstanding common stock, including shares held by Garrett Calloway (Chairman and CEO), Elaine Briggs (President, Development), Marcus Yoon (CFO), and other members of our senior management team.

• Earlier-stage investors and employees hold the remaining approximately 14% of our outstanding common stock, including shares issued pursuant to our pre-IPO equity incentive plans.

In this offering, we are proposing to sell common stock with an aggregate offering size of approximately $600,000,000 on the New York Stock Exchange under the ticker symbol "CBRI," at an assumed midpoint offering price of $22.00 per share. The offering consists of the following components:

• Primary shares (shares sold by the Company): approximately $371,700,000, or 16,895,455 shares. The Company will receive all net proceeds from the sale of primary shares.

• Secondary shares (shares sold by Pinnacle Vista): approximately $150,000,000, or 6,818,182 shares. The Company will not receive any proceeds from the sale of secondary shares.

We intend to use the net proceeds from the sale of primary shares in this offering as follows:

• approximately $200 million to repay a portion of the outstanding balance under our Corporate Term Loan B facility with Veltrano National Bank (including a prepayment premium of 1.00%, or $2.0 million);

• approximately $100 million to fund a portion of the construction costs of the Cimarron Solar project in Doña Ana County, New Mexico (expected COD Q1 2023); and

• approximately $71.7 million for general corporate purposes, including working capital and potential development expenditures for projects in our 6.2 GW development pipeline.

For additional information regarding our use of proceeds, see "Use of Proceeds" elsewhere in this prospectus.

1.6 Key Factors Affecting Our Results of Operations

Our financial performance is influenced by a number of key factors, including the following:

Growth in Operating Capacity. Our revenue and profitability are directly correlated to the size of our operating portfolio. We grew our operating capacity from approximately 2.1 GW at the end of fiscal year 2019 to approximately 3.8 GW at the end of fiscal year 2021, driven by the successful completion and commencement of commercial operations at multiple new projects. We expect our operating capacity to continue to grow as projects currently under construction (Mesquite Wind and Cimarron Solar) achieve COD and as we advance projects from our development pipeline into construction.

PPA Pricing and Contract Terms. The majority of our revenue is derived from long-term PPAs with fixed or escalating pricing. The contracted rates under our PPAs, including any contractual escalation provisions (which are typically tied to a fixed annual percentage or a consumer price index), are a primary determinant of our revenue. In addition, PPA terms related to curtailment — the reduction or interruption of energy deliveries at the direction of the grid operator or offtaker — can impact our realized revenue. Curtailment provisions vary by contract, with some PPAs requiring the offtaker to compensate us for curtailed energy and others allocating curtailment risk to the generator.

Weather Patterns, Solar Irradiance, and Wind Resource Variability. Our generation volumes are dependent on weather conditions, including solar irradiance levels and wind speeds, which are inherently variable on a daily, seasonal, and annual basis. While we select project sites based on long-term resource assessments and design our portfolio to diversify across geographies and technologies, actual generation in any given period may vary from our expectations.

Availability and Cost of Equipment, Labor, and Supply-Chain Constraints. The cost and timely delivery of key equipment — including solar panels, wind turbines, battery cells, inverters, and balance-of-system components — are critical to the economics of our construction-stage and development-stage projects. We have experienced, and may continue to experience, supply-chain disruptions, tariff-related cost increases, and labor shortages that could increase project costs or delay construction timelines.

Tax Incentive Environment. Our projects benefit from federal tax incentives, including Investment Tax Credits ("ITCs") for solar and battery storage projects and Production Tax Credits ("PTCs") for wind projects. The availability, magnitude, and duration of these tax incentives significantly impact the economics of our projects and our ability to attract tax-equity financing. Changes in tax legislation or regulations, or adverse interpretations of existing tax rules by the Internal Revenue Service, could affect the value of these incentives.

Interest Rate Environment. We rely on significant amounts of project-finance and corporate-level debt to fund our operations and growth. Our interest expense is sensitive to changes in benchmark interest rates, as a substantial portion of our debt bears interest at variable rates tied to the Secured Overnight Financing Rate ("SOFR"). Rising interest rates increase our cost of capital and may impact the economics of new project development and financing.

Regulatory Environment. Our operations are subject to extensive federal, state, and local regulations across our five operating states (Texas, New Mexico, Arizona, California, and Oklahoma). Changes in energy policy, environmental regulations, permitting requirements, or transmission interconnection rules could affect our ability to develop, construct, and operate projects.

Electricity Market Dynamics. Our projects operate within several independent system operator ("ISO") and regional transmission organization ("RTO") markets, including the Electric Reliability Council of Texas ("ERCOT"), the Southwest Power Pool ("SPP"), and the California Independent System Operator ("CAISO"). Wholesale electricity prices, transmission congestion, locational marginal pricing, and market rules in these jurisdictions directly affect our merchant revenue and, to a lesser extent, our contracted revenue.

1.7 Key Business Metrics

We monitor a number of key operating and financial metrics to evaluate our business performance, allocate resources, and assess the health of our portfolio. These metrics include:

• Operating Capacity (GW): Total nameplate capacity of projects that have achieved COD and are delivering energy to the grid.

• Generation (GWh): Total electricity generated by our operating portfolio, measured in gigawatt-hours.

• Contracted Revenue Percentage: The percentage of our total revenue derived from long-term PPAs, as opposed to merchant energy sales or ancillary services. A higher contracted revenue percentage indicates greater revenue predictability.

• Adjusted EBITDA (non-GAAP): A supplemental non-GAAP financial measure that we use to evaluate our operating performance. See "Adjusted EBITDA Reconciliation" below for the definition of Adjusted EBITDA and a reconciliation to the most directly comparable GAAP measure.

• Project-Level Availability Factors: The percentage of time that our projects are available to generate electricity, taking into account scheduled and unscheduled maintenance outages. Higher availability factors indicate more reliable operations.

• Development Pipeline (GW): Total nameplate capacity of projects in various stages of development that have not yet commenced construction.

These metrics are not intended to be substitutes for, or superior to, any measure calculated in accordance with GAAP. See "Key Components of Our Results of Operations" and "Adjusted EBITDA Reconciliation" below for additional information.

2. Key Components of Our Results of Operations

The following is a description of the key components of our consolidated results of operations.

2.1 Revenue. We derive our revenue from the following principal sources:

PPA Revenue. The majority of our revenue is derived from long-term PPAs with investment-grade utility and C&I counterparties. These agreements typically have terms ranging from 10 to 25 years and provide for the sale of electricity generated by our projects at contracted rates that are either fixed for the duration of the agreement or subject to contractual escalation provisions (typically ranging from 1.0% to 2.5% per annum). Revenue under our PPAs is generally recognized as energy is generated and delivered to the applicable delivery point at the contracted rate for the relevant period. PPA pricing reflects range factors, including the technology type, project location, term of the agreement, time-of-delivery pricing features, and prevailing wholesale electricity market conditions at the time the PPA was executed. Our PPAs are entered into with a diverse group of counterparties, including investor-owned utilities, municipal utilities, electric cooperatives, and large C&I customers, substantially all of which carry investment-grade credit ratings or provide adequate credit support.

Merchant Revenue. A portion of our revenue is derived from the sale of electricity at prevailing wholesale market prices in the ISO and RTO markets in which our projects operate. Merchant revenue arises from projects or portions of projects that are not subject to long-term PPA contracts, as well as from generation volumes that exceed contracted volumes under existing PPAs. Merchant revenue is inherently more variable than PPA revenue, as it is subject to fluctuations in wholesale electricity prices driven by supply and demand dynamics, fuel prices, weather conditions, and other market factors. For the fiscal year ended December 31, 2021, merchant revenue represented approximately 11% of our total revenue.

Ancillary Services Revenue. We earn revenue from the provision of ancillary services to grid operators, including frequency regulation, voltage support, spinning reserves, and participation in capacity markets. Ancillary services revenue is primarily generated by our Brazos Storage battery project (200 MW / 800 MWh, COD Q4 2021), which is capable of providing rapid-response grid services that are increasingly valued by grid operators as the penetration of variable renewable energy resources increases. We also earn limited ancillary services revenue from certain of our wind and solar projects. For the fiscal year ended December 31, 2021, ancillary services revenue represented approximately 5% of our total revenue.

Tax Attribute Revenue / Tax-Equity Income Allocation. Revenue and income allocation related to our tax-equity partnership arrangements, including the Solaris West partnership with Veltara Basin Financial LLC, are an important component of our financial results. We account for our tax-equity partnerships using the Hypothetical-Liquidation-at-Book-Value ("HLBV") methodology, which results in the allocation of partnership income and loss between us and the tax-equity investor based on changes in each partner's claim on the net assets of the partnership at each reporting date. The HLBV methodology can result in the recognition of significant amounts of income or loss in periods when tax attributes (such as ITCs or accelerated depreciation) are allocated to the tax-equity investor, even when the underlying cash flows from the project may be relatively stable. See "Critical Accounting Policies and Estimates — Tax-Equity Accounting — HLBV Methodology" below for additional information.

2.2 Cost of Revenue

Our cost of revenue consists primarily of the following:

• Operations and Maintenance ("O&M") Costs. We incur costs for the ongoing operations and maintenance of our renewable energy projects, including both in-house O&M staff costs and payments under third-party O&M contracts with original equipment manufacturers and specialized service providers. O&M costs include routine inspections, preventive maintenance, corrective maintenance, spare parts, and vegetation management.

• Land Lease and Easement Payments. We make recurring payments under long-term land lease and easement agreements with landowners at each of our project sites. These agreements typically have terms coterminous with or exceeding the expected useful lives of the projects and include periodic escalation provisions.

• Transmission and Interconnection Costs. We incur costs for transmission access and interconnection to the electric grid, including network upgrade payments, wheeling charges, and ongoing interconnection-related fees paid to grid operators and transmission owners.

• Insurance Costs. We maintain comprehensive insurance coverage for our projects, including property insurance, general liability insurance, and builder's risk insurance for construction-stage projects. Insurance premiums are a significant component of our cost of revenue and have increased in recent periods due to rising insured values and industry-wide increases in renewable energy insurance premiums.

• Depreciation and Amortization of Renewable Energy Assets. We depreciate our solar, wind, and battery storage assets over their estimated useful lives on a straight-line basis. Depreciation of renewable energy assets is included in cost of revenue and represents one of the largest non-cash components of our cost structure.

2.3 Gross Profit

Gross profit represents revenue less cost of revenue. Our gross margins are influenced by a number of factors, including our technology mix (solar, wind, and storage projects have different cost profiles and margin characteristics), PPA pricing and escalation terms, the proportion of revenue derived from merchant sales versus contracted PPAs, curtailment levels, and the efficiency of our O&M operations. Generally, our solar and wind projects generate higher gross margins than our storage projects, which have higher operating costs relative to revenue but provide valuable portfolio diversification and ancillary services capability. We expect our gross margins to remain relatively stable as we grow our operating portfolio, although margin variability may occur in any given quarter or year due to weather, curtailment events, or changes in merchant electricity prices.

2.4 General and Administrative Expenses

General and administrative ("G&A") expenses include salaries, wages, and benefits for our approximately 1,240 employees (including corporate, development, and administrative personnel), professional services fees (including legal, accounting, and consulting fees), equity-based compensation expense, office rent and facilities costs, information technology expenses, travel and entertainment costs, and corporate insurance premiums. Our corporate insurance program includes a directors' and officers' ("D&O") liability insurance tower with aggregate limits of $50 million, with Meridian National Assurance Company serving as the primary carrier and an annual premium of approximately $1.87 million. We expect G&A expenses to increase in absolute terms as we grow our business and incur additional costs associated with operating as a public company following this offering, including SEC reporting and compliance costs, NYSE listing fees, incremental D&O insurance premiums, SOX compliance costs, investor relations expenses, and incremental audit and legal fees.

2.5 Development Expenses

Development expenses consist of pre-construction development costs for pipeline projects that have not yet met the capitalization thresholds established under our accounting policies. These costs include expenditures related to site identification and assessment, resource measurement campaigns, permitting and environmental assessment studies, interconnection study and queue management costs, community engagement activities, and early-stage engineering and design work. Development expenses are expensed as incurred until such time as a project meets the criteria for capitalization, which generally occurs when the project has received all material permits, executed an interconnection agreement, and achieved other milestones indicating that construction is probable. Development expenses can vary significantly from period to period depending on the number and stage of projects in our development pipeline.

2.6 Depreciation and Amortization

Depreciation and amortization expense consists of the depreciation of our renewable energy generation and storage assets, balance-of-system equipment, transmission infrastructure, and other tangible assets, as well as the amortization of intangible assets, including the fair value of PPAs acquired in project acquisitions. Our renewable energy assets are depreciated on a straight-line basis over their estimated useful lives, which are generally 25 to 35 years for solar PV systems and onshore wind turbines and 15 to 20 years for battery energy storage systems. Depreciation and amortization is a significant non-cash expense and is expected to increase as we bring additional projects into service. A portion of depreciation and amortization is included in cost of revenue (for operating project assets), and the remainder is included as a separate line item below gross profit (for corporate and other assets).

2.7 Interest Expense

Interest expense consists of interest on our corporate-level indebtedness and our project-level indebtedness, as well as the amortization of deferred debt issuance costs and original issue discount associated with our debt facilities. Our corporate-level debt includes:

• Corporate Revolving Credit Facility: A $400,000,000 revolving credit facility with Veltrano National Bank, as Administrative Agent, maturing in January 2027. This facility is available for working capital and general corporate purposes and bears interest at a variable rate based on SOFR plus an applicable margin.

• Corporate Term Loan B: A $650,000,000 term loan facility with Veltrano National Bank, as Administrative Agent, maturing in January 2029, of which $612.5 million was outstanding as of December 31, 2021. This facility bears interest at a variable rate based on SOFR plus an applicable margin and is secured by substantially all assets of CBR and its subsidiaries, other than project-level assets pledged to project-finance lenders.

Our project-level debt includes:

• Mesquite Wind Construction-to-Term Facility: A $165,000,000 construction-to-term facility with Prairie Commercial Bank, N.A., with a construction-to-term conversion date of December 2024. This facility is non-recourse to CBR (other than a limited completion guarantee) and is secured by the assets of Mesquite Wind Holdings LLC.

• Cimarron Solar Construction-to-Term Facility: A $143,000,000 construction-to-term facility with Prairie Commercial Bank, N.A., with a construction-to-term conversion date of March 2025. This facility is non-recourse to CBR (other than a limited completion guarantee) and is secured by the assets of Cimarron Solar Development LLC.

During the construction phase of our projects, we capitalize a portion of interest expense attributable to qualifying construction-stage assets in accordance with ASC 835-20, Interest — Capitalization of Interest. Capitalized interest reduces the amount of interest expense recognized in our consolidated statements of operations and is included in the cost basis of the related project assets, where it is subsequently depreciated over the useful life of the asset.

2.8 Income Tax Expense (Benefit)

We are organized as a C-corporation and are subject to U.S. federal income tax at the statutory rate of 21%, as well as applicable state and local income and franchise taxes in the jurisdictions in which we operate. Our effective income tax rate differs from the statutory federal rate due to the impact of state and local taxes, federal tax incentives (ITCs and PTCs), tax-equity partnership income allocations, permanent book-tax differences, and changes in deferred tax assets and liabilities. We have tax nexus in Texas, New Mexico, Arizona, California, and Oklahoma.

ITCs and PTCs are the most significant items impacting our effective tax rate. ITCs, which are available for qualifying solar and battery storage projects, provide a credit against federal income tax equal to a percentage (currently 26% to 30%, depending on the date construction began) of the eligible cost basis of the project. PTCs, which are available for qualifying wind projects, provide a per-kilowatt-hour credit for electricity generated and sold during the first ten years of a project's operation. The recognition and allocation of these tax credits can result in significant period-to-period variability in our effective tax rate and income tax expense.

2.9 Adjusted EBITDA (Non-GAAP Measure)

We define Adjusted EBITDA as net income (loss) before interest expense (net of interest income), income tax expense (benefit), depreciation and amortization, equity-based compensation expense, unrealized gains and losses on derivative instruments, acquisition and development costs that do not meet capitalization thresholds, and certain non-recurring items. We present Adjusted EBITDA because management believes it is a useful supplemental measure for evaluating our core operating performance across periods, comparing our results with those of other companies in the renewable energy industry, and assessing our ability to service debt and fund capital expenditures. Adjusted EBITDA has limitations as an analytical tool and should not be considered in isolation or as a substitute for net income (loss), operating income (loss), cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP. Other companies in the renewable energy industry may calculate Adjusted EBITDA differently than we do, which limits its usefulness as a comparative measure. For a reconciliation of Adjusted EBITDA to the most directly comparable GAAP measure, net income (loss), see "Adjusted EBITDA Reconciliation" below.

3. Results of Operations

3.1 Comparison of Fiscal Year Ended December 31, 2021 vs. Fiscal Year Ended December 31, 2020

The following table sets forth selected consolidated statements of operations data for the periods indicated:

3.1.1 Revenue. Revenue for the fiscal year ended December 31, 2021 was $487.3 million, an increase of $85.8 million, or 21.4%, compared to $401.5 million for the fiscal year ended December 31, 2020. This increase was primarily driven by the following factors:

• New project contributions. The addition of the Pronghorn Wind project (510 MW, COD Q2 2021) in Nolan County, Texas contributed $54.2 million of incremental revenue following the commencement of commercial operations in June 2021. The Brazos Storage project (200 MW / 800 MWh, COD Q4 2021) in Fort Bend County, Texas contributed $8.9 million of revenue, including energy arbitrage and ancillary services revenue, during its initial operating period from November through December 2021.

• Full-year contributions from recently completed projects. The Solaris West project (450 MW, COD Q3 2020) contributed $38.7 million of incremental revenue in fiscal year 2021, reflecting a full twelve months of operations compared to only four and a half months following its COD in August 2020. Similarly, the Painted Rock Solar project (320 MW, COD Q4 2020) contributed $22.4 million of incremental revenue, reflecting a full twelve months of operations compared to approximately two months of operations in fiscal year 2020.

• Favorable resource conditions. Solar irradiance across our Texas, Arizona, and New Mexico project sites exceeded our long-term P50 resource estimates by approximately 3.2% during fiscal year 2021, contributing to higher-than-expected solar generation. Wind resources at our Oklahoma and Texas wind project sites were generally in line with long-term expectations.

• PPA escalator adjustments. Contractual annual escalation provisions under our existing PPAs increased contracted revenue rates by an average of approximately 1.8% on a portfolio-weighted basis.

These favorable factors were partially offset by:

• ERCOT winter storm curtailment. In February 2021, an unprecedented winter storm event in Texas resulted in widespread power outages and grid instability across the ERCOT market. Certain of our Texas-based wind and solar projects experienced forced curtailments and weather-related outages during this event, resulting in an estimated revenue impact of approximately $(12.3) million during the first quarter of 2021. While a portion of this lost revenue was mitigated by favorable real-time pricing during the event for our projects that remained operational, the net impact was negative.

• Scheduled maintenance outages at Red Mesa Wind. The Red Mesa Wind project (380 MW) in Custer County, Oklahoma underwent a planned major maintenance campaign during the third quarter of 2021, which included gearbox inspections and blade maintenance on a significant portion of the turbine fleet. This maintenance campaign resulted in reduced generation and an estimated revenue impact of approximately $(4.1) million during the quarter.

3.1.2 Cost of Revenue and Gross Profit. Cost of revenue for the fiscal year ended December 31, 2021 was $303.1 million, an increase of $46.4 million, or 18.1%, compared to $256.7 million for the fiscal year ended December 31, 2020. This increase was primarily attributable to:

• Higher O&M costs associated with the expanded operating fleet, including the addition of the Pronghorn Wind and Brazos Storage projects and full-year operations of the Solaris West and Painted Rock Solar projects. Incremental O&M costs for these projects totaled approximately $21.8 million.

• Increased land lease payments of approximately $6.3 million, reflecting lease escalation provisions and new lease obligations associated with the Pronghorn Wind and Brazos Storage project sites.

• Higher insurance premiums of approximately $4.7 million, driven by increased insured values from fleet expansion and industry-wide increases in renewable energy property insurance rates.

• Increased depreciation and amortization of approximately $13.6 million included in cost of revenue, reflecting the commencement of depreciation on the Pronghorn Wind and Brazos Storage assets placed in service during fiscal year 2021.

Gross profit for fiscal year 2021 was $184.2 million, an increase of $39.4 million, or 27.2%, compared to $144.8 million for fiscal year 2020. Gross margin (gross profit as a percentage of revenue) improved to 37.8% in fiscal year 2021 from 36.1% in fiscal year 2020. The improvement in gross margin was primarily driven by the operating leverage achieved as our fixed-cost base (including land leases and certain O&M costs) was spread across a larger revenue base, as well as the favorable resource conditions described above. This improvement was partially offset by the higher insurance costs and the February 2021 winter storm impact discussed above.

3.1.3 General and Administrative Expenses. G&A expenses for fiscal year 2021 were $62.4 million, an increase of $13.1 million, or 26.6%, compared to $49.3 million for fiscal year 2020. This increase was primarily attributable to:

• Headcount growth from approximately 1,050 employees at the end of fiscal year 2020 to approximately 1,240 employees at the end of fiscal year 2021, resulting in approximately $6.8 million of incremental salary, benefits, and related personnel costs. The headcount increase was driven by the need to support our expanded operating portfolio, our growing development pipeline, and our preparations for operating as a public company.

• IPO-preparation costs of approximately $3.2 million incurred during fiscal year 2021, including legal fees associated with the preparation of the registration statement, accounting fees related to the audit of additional historical periods and implementation of public-company accounting policies, and consulting fees for SOX 404 readiness assessments.

• Equity-based compensation expense of approximately $8.4 million in fiscal year 2021, an increase of $3.1 million from $5.3 million in fiscal year 2020, driven by new equity grants made to employees in connection with our growth and retention initiatives.

3.1.4 Depreciation and Amortization. Total depreciation and amortization expense (including amounts included in cost of revenue and amounts reported as a separate operating expense) was $118.4 million for fiscal year 2021, compared to $96.1 million for fiscal year 2020, an increase of $22.3 million, or 23.2%. This increase was primarily attributable to the commencement of depreciation on the Pronghorn Wind project assets (placed in service in Q2 2021) and the Brazos Storage project assets (placed in service in Q4 2021), which together contributed approximately $19.7 million of incremental depreciation expense. The remainder of the increase was attributable to full-year depreciation on the Solaris West and Painted Rock Solar project assets, which were placed in service during fiscal year 2020.

3.1.5 Interest Expense. Net interest expense for fiscal year 2021 was $54.2 million, an increase of $5.6 million, or 11.5%, compared to $48.6 million for fiscal year 2020. This increase was primarily driven by:

• Increased borrowings under the Corporate Term Loan B facility, which was drawn to fund a portion of the construction costs for the Pronghorn Wind and Brazos Storage projects. The average outstanding balance under the Term Loan B increased from approximately $535 million during fiscal year 2020 to approximately $595 million during fiscal year 2021.

• Initial draws under the Mesquite Wind construction-to-term facility ($165 million commitment with Prairie Commercial Bank, N.A.), which commenced in the fourth quarter of 2021. Interest on Mesquite Wind construction draws totaled approximately $1.3 million for fiscal year 2021.

• These increases were partially offset by $7.8 million of capitalized interest during fiscal year 2021 related to the Mesquite Wind and Cimarron Solar construction-stage projects, compared to $4.2 million of capitalized interest during fiscal year 2020 related to the Pronghorn Wind and Brazos Storage construction-stage projects.

The weighted average effective interest rate on our total outstanding debt was approximately 4.1% during fiscal year 2021, compared to approximately 4.3% during fiscal year 2020, reflecting the impact of declining SOFR rates during the period.

3.1.6 Income Tax Expense. Income tax expense for fiscal year 2021 was $7.2 million, compared to $18.6 million for fiscal year 2020, a decrease of $11.4 million. Our effective income tax rate for fiscal year 2021 was approximately 14.7%, compared to approximately 56.9% for fiscal year 2020. The decrease in our effective tax rate and income tax expense was primarily driven by:

• The recognition of ITCs associated with the Pronghorn Wind project, which qualified for a 26% ITC based on the date construction began. The ITC for Pronghorn Wind was recognized upon the project's achievement of COD in Q2 2021 and resulted in a significant reduction in income tax expense.

• Continued recognition of PTCs generated by the Red Mesa Wind project, which is in its third year of the ten-year PTC eligibility period. PTC income recognized during fiscal year 2021 was approximately $7.8 million.

• These favorable items were partially offset by higher pre-tax income in fiscal year 2021, which increased the baseline federal and state income tax liability before consideration of tax credits.

The effective tax rate for fiscal year 2020 was unusually high relative to the statutory rate due to a provision for uncertain tax positions related to ITC eligibility for a portion of the Painted Rock Solar project's cost basis, which was resolved favorably in fiscal year 2021. Excluding this discrete item, the effective tax rate for fiscal year 2020 would have been approximately 23.4%.

Our deferred tax assets and liabilities are discussed in greater detail in the notes to our consolidated financial statements included elsewhere in this prospectus.

3.1.7 Net Income. Net income for fiscal year 2021 was $41.7 million, an increase of $27.6 million, or 195.7%, compared to net income of $14.1 million for fiscal year 2020. This increase was driven by the $85.8 million increase in revenue from our expanded operating portfolio, improved gross margins from operating leverage and favorable resource conditions, and the significant reduction in income tax expense resulting from the recognition of tax credits associated with the Pronghorn Wind project, partially offset by increases in cost of revenue, G&A expenses, depreciation and amortization, and interest expense as described above.

3.2 Comparison of Fiscal Year Ended December 31, 2020 vs. Fiscal Year Ended December 31, 2019

The following table sets forth selected consolidated statements of operations data for the periods indicated:

3.2.1 Revenue. Revenue for the fiscal year ended December 31, 2020 was $401.5 million, an increase of $88.7 million, or 28.4%, compared to $312.8 million for the fiscal year ended December 31, 2019. This increase was primarily driven by:

• New project contributions. The addition of the Solaris West project (450 MW, COD Q3 2020) in Pecos County, Texas contributed $27.8 million of revenue following the commencement of commercial operations in August 2020. The Painted Rock Solar project (320 MW, COD Q4 2020) in Maricopa County, Arizona contributed $8.4 million of revenue following its COD in November 2020. Together, these two projects represented the largest incremental additions to our operating portfolio during fiscal year 2020.

• Full-year contribution of Red Mesa Wind. The Red Mesa Wind project (380 MW, COD Q1 2019) in Custer County, Oklahoma contributed $43.6 million of incremental revenue in fiscal year 2020, reflecting a full twelve months of operations compared to approximately ten months of operations in fiscal year 2019 (following its March 2019 COD).

• Portfolio optimization. We implemented a number of operational improvements across our existing portfolio during fiscal year 2020, including upgraded monitoring systems, optimized turbine yaw control algorithms at our wind projects, and enhanced panel cleaning protocols at our solar projects. These initiatives contributed to improved generation output and an estimated $8.9 million of incremental revenue across the existing portfolio.

These favorable factors were partially offset by lower-than-expected wind resources at certain of our Texas-based wind projects during the third and fourth quarters of fiscal year 2020, which resulted in an estimated revenue shortfall of approximately $(5.6) million relative to our internal forecasts.

3.2.2 Cost of Revenue and Gross Profit. Cost of revenue for fiscal year 2020 was $256.7 million, an increase of $45.4 million, or 21.5%, compared to $211.3 million for fiscal year 2019. The increase was driven primarily by higher O&M costs and depreciation expense associated with the expanded operating fleet, including the Solaris West and Painted Rock Solar projects and a full year of operations at Red Mesa Wind. Land lease payments increased by approximately $4.8 million, and insurance premiums increased by approximately $3.1 million.

Gross profit for fiscal year 2020 was $144.8 million, an increase of $43.3 million, or 42.7%, compared to $101.5 million for fiscal year 2019. Gross margin improved to 36.1% in fiscal year 2020 from 32.4% in fiscal year 2019. The significant improvement in gross margin was attributable to economies of scale as our revenue base grew faster than our semi-variable and fixed cost of revenue components, as well as the favorable impact of the portfolio optimization initiatives described above.

3.2.3 General and Administrative Expenses. G&A expenses for fiscal year 2020 were $49.3 million, an increase of $7.7 million, or 18.5%, compared to $41.6 million for fiscal year 2019. The increase was primarily driven by headcount growth from approximately 900 employees at the end of fiscal year 2019 to approximately 1,050 employees at the end of fiscal year 2020, resulting in approximately $5.2 million of incremental personnel costs. Additionally, equity-based compensation expense increased by approximately $1.4 million as additional grants were made to new hires and existing employees, and professional services fees increased by approximately $1.1 million related to pre-IPO planning activities and tax advisory services.

3.2.4 Depreciation and Amortization. Total depreciation and amortization expense was $96.1 million for fiscal year 2020, compared to $78.3 million for fiscal year 2019, an increase of $17.8 million, or 22.7%. This increase was primarily attributable to the commencement of depreciation on the Solaris West project assets (placed in service in Q3 2020) and the Painted Rock Solar project assets (placed in service in Q4 2020), as well as a full year of depreciation on the Red Mesa Wind project assets (placed in service in Q1 2019).

3.2.5 Interest Expense. Net interest expense for fiscal year 2020 was $48.6 million, a decrease of $3.5 million, or 6.7%, compared to $52.1 million for fiscal year 2019, despite an increase in total outstanding debt. This decrease was primarily attributable to lower benchmark interest rates during fiscal year 2020, as SOFR declined significantly in response to the Federal Reserve's monetary policy actions in connection with the COVID-19 pandemic, which reduced the floating-rate interest expense on our corporate and project-level debt facilities. The benefit of lower interest rates was partially offset by higher average outstanding borrowings under the Corporate Term Loan B, which was drawn to fund construction of the Solaris West and Painted Rock Solar projects.

In fiscal year 2019, we received a follow-on equity investment of $120 million from Pinnacle Vista Capital Partners III, LP, which was used to fund a portion of our development and construction activities and reduced our near-term reliance on debt financing. This equity contribution contributed to a favorable capital structure and partially mitigated the growth in interest expense that would have otherwise occurred.

3.2.6 Income Tax Expense. Income tax expense for fiscal year 2020 was $18.6 million, compared to $18.8 million for fiscal year 2019, a decrease of $0.2 million. Despite the significant increase in pre-tax income from fiscal year 2019 to fiscal year 2020, income tax expense remained relatively flat due to the recognition of ITCs associated with the Solaris West project, which achieved COD in Q3 2020 and qualified for a 26% ITC. The effective income tax rate for fiscal year 2020 was approximately 56.9% (which, as noted above, was elevated by a provision for uncertain tax positions related to Painted Rock Solar ITC eligibility). The effective income tax rate for fiscal year 2019 was not meaningful due to the net loss recorded in that year; however, the income tax benefit of $18.8 million for fiscal year 2019 was primarily driven by PTCs generated by the Red Mesa Wind project and a deferred tax benefit associated with net operating loss carryforwards.

3.2.7 Net Income (Loss). Net income for fiscal year 2020 was $14.1 million, compared to a net loss of $(22.4) million for fiscal year 2019, representing a swing of $36.5 million. This transition to profitability was driven by:

• The $88.7 million increase in revenue from our expanded operating portfolio;

• Improved operating leverage, as reflected in the 370 basis point improvement in gross margin;

• The favorable impact of ITC recognition associated with the Solaris West project;

• Lower interest expense resulting from the declining rate environment; and

• Partially offset by increases in G&A expenses and depreciation and amortization.

The net loss in fiscal year 2019 reflected the earlier stage of our business, in which a significant portion of our portfolio was under construction and had not yet commenced generating revenue, and the interest costs associated with construction-stage debt were partially recognized in the income statement (net of capitalized interest). The transition to profitability in fiscal year 2020 marked an important inflection point in our financial trajectory as the revenue contributions from newly operational projects outpaced the growth in our cost structure.

3.3 Quarterly Results: Three Months Ended March 31, 2022 vs. Three Months Ended March 31, 2021 (Unaudited)

The following table sets forth selected unaudited condensed consolidated statements of operations data for the periods indicated:

3.3.1 Revenue. Revenue for the three months ended March 31, 2022 was $131.4 million (unaudited), an increase of $26.7 million, or 25.5%, compared to $104.7 million for the three months ended March 31, 2021. The increase was driven by:

• The full operating portfolio of 3.8 GW being online for the entirety of Q1 2022, compared to only 2.2 GW at the beginning of Q1 2021 (prior to the Pronghorn Wind and Brazos Storage CODs).

• A significant contribution from the Brazos Storage project (200 MW / 800 MWh), which completed its first full quarter of operations in Q1 2022 and generated approximately $10.8 million in revenue, including energy arbitrage and ancillary services income. During Q1 2022, ERCOT experienced several periods of high electricity price volatility, which provided favorable conditions for battery storage operations.

• The absence of the February 2021 winter storm impact, which had reduced Q1 2021 revenue by an estimated $(12.3) million due to forced curtailments and weather-related outages at our Texas-based projects.

• Seasonal wind patterns were generally favorable in Q1 2022, with the Pronghorn Wind and Red Mesa Wind projects generating above-expectation output during February and March.

Partially offsetting these favorable factors, Q1 2022 solar generation at our Solaris West and Painted Rock Solar projects was slightly below expectations due to higher-than-average cloud cover during portions of January and February.

3.3.2 Other Line Items. Cost of revenue for Q1 2022 was $82.6 million, an increase of $14.8 million from Q1 2021, reflecting the larger operating fleet and associated O&M, depreciation, and other costs. Gross margin improved to 37.1% in Q1 2022 from 35.2% in Q1 2021, driven by the revenue scale benefits and the absence of the winter storm impact.

G&A expenses for Q1 2022 were $18.3 million, an increase of $4.5 million from Q1 2021, driven by continued headcount growth, equity-based compensation expense, and accelerating IPO-preparation costs, including incremental legal and accounting fees.

Development expenses for Q1 2022 were $5.4 million, an increase of $1.7 million from Q1 2021, reflecting increased pre-construction activity for the Silverleaf Wind and Copper Basin Solar + Storage development projects.

Interest expense for Q1 2022 was $14.6 million, an increase of $1.8 million from Q1 2021, reflecting higher outstanding borrowings under the Mesquite Wind and Cimarron Solar construction facilities, partially offset by continued capitalization of interest on qualifying construction-stage assets.

Income tax expense for Q1 2022 was $2.2 million, reflecting an estimated annual effective tax rate of approximately 21.0% before discrete items. The effective rate was closer to the statutory rate in Q1 2022 as no significant discrete tax credit items were recognized during the quarter.

Net income for Q1 2022 was $8.3 million (unaudited), an increase of $2.6 million from Q1 2021 net income of $5.7 million.

Adjusted EBITDA for Q1 2022 was $59.8 million (unaudited), compared to $47.2 million for Q1 2021, an increase of $12.6 million, or 26.7%, primarily driven by the revenue growth and margin improvement described above.

4. Adjusted EBITDA Reconciliation

4.1 Reconciliation Table

The following table presents a reconciliation of Adjusted EBITDA to net income (loss), the most directly comparable GAAP measure, for each of the periods presented:

Non-recurring and other items for each period consisted primarily of the following:

• FY 2019: $8.6 million of acquisition-related costs in connection with the portfolio acquisition of two operating wind projects, $3.1 million of costs related to the Pinnacle Vista follow-on equity investment, and $1.5 million of other non-recurring items, including legal settlements.

• FY 2020: $4.7 million of early-stage development costs for projects that did not meet capitalization thresholds and were subsequently abandoned, $2.4 million of costs related to refinancing of the Corporate Revolving Credit Facility, and $1.2 million of other non-recurring items.

• FY 2021: $3.2 million of IPO-preparation costs (primarily legal and accounting fees), $2.1 million of costs associated with the February 2021 ERCOT winter storm event (including emergency repair costs and insurance deductibles), and $1.6 million of other non-recurring items, including costs related to the amendment of the corporate credit agreement.

• Q1 2022 (Unaudited): $1.8 million of IPO-preparation costs and $0.4 million of other non-recurring items.

4.2 Limitations of Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure and has important limitations as an analytical tool. Adjusted EBITDA should not be considered as a substitute for, or superior to, net income (loss), operating income (loss), cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP. Among the limitations of Adjusted EBITDA are the following:

• Adjusted EBITDA does not reflect our cash expenditures, or future requirements, for capital expenditures or contractual commitments;

• Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs;

• Adjusted EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our corporate and project-level indebtedness;

• Adjusted EBITDA does not reflect our income tax expense or the cash requirements to pay our income taxes;

• Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements;

• Adjusted EBITDA does not reflect the impact of equity-based compensation expense, which is a recurring expense and an important component of our overall compensation strategy; and

• Other companies in the renewable energy industry may calculate Adjusted EBITDA or similarly titled measures differently than we do, which limits its usefulness as a comparative measure.

Because of these and other limitations, Adjusted EBITDA should be considered alongside, not as an alternative to, net income (loss) and other GAAP measures. Investors are encouraged to review the reconciliation of Adjusted EBITDA to net income (loss) set forth above and to not rely on any single financial measure to evaluate our business.

5. Liquidity and Capital Resources

5.1 Overview. We have historically funded our operations, project development, and capital expenditures through a combination of project-finance debt, corporate-level debt, tax-equity investments, and equity contributions from our investors, including Pinnacle Vista Capital Partners III, LP and our founders and management team. Our principal sources of liquidity include cash on hand, cash flows generated from our operating portfolio, availability under our Corporate Revolving Credit Facility, and, following this offering, the net proceeds from the sale of primary shares in this offering.

As of December 31, 2021, we had total assets of approximately $3.94 billion, total debt of approximately $1.71 billion (including both corporate-level and project-level indebtedness), and cash and cash equivalents of approximately $185 million. As of March 31, 2022 (unaudited), our total assets were approximately $4.07 billion, total debt was approximately $1.74 billion, and cash and cash equivalents were approximately $167 million. The increase in total assets and total debt from December 31, 2021 to March 31, 2022 was primarily attributable to continued construction draws under the Mesquite Wind and Cimarron Solar construction facilities and the capitalization of construction costs.

We believe that our current cash and cash equivalents, cash flows from operating activities, availability under our Corporate Revolving Credit Facility, and the anticipated net proceeds from this offering will be sufficient to meet our anticipated cash needs, including operating expenses, capital expenditures, debt service obligations, and development expenditures, for at least the next twelve months from the date of this prospectus. However, our actual cash needs may differ from our current expectations due to range factors, and we may seek additional financing in the future through debt or equity offerings, project-level financings, or other capital-raising transactions.

5.2 Sources of Liquidity

5.2.1 Cash Flows from Operations. Our operating cash flows are primarily derived from PPA revenue generated by our operating portfolio, supplemented by merchant energy sales and ancillary services revenue. Operating cash flows are influenced by generation volumes (which are dependent on weather and resource conditions), contracted PPA rates, merchant electricity prices, the timing of collections from offtakers, and working capital fluctuations. We expect our operating cash flows to increase over time as we bring additional projects into service and our operating portfolio continues to grow.

5.2.2 Corporate Credit Facilities (Veltrano National Bank). Corporate Revolving Credit Facility. We maintain a $400,000,000 senior secured revolving credit facility (the "Revolver") with Veltrano National Bank, as Administrative Agent, and a syndicate of lenders. The Revolver matures in January 2027 and is available for working capital, general corporate purposes, and to support letters of credit. Borrowings under the Revolver bear interest at a variable rate based on the term SOFR plus an applicable margin that varies based on our consolidated total leverage ratio, ranging from 2.00% to 2.75% per annum. The Revolver is secured by substantially all assets of CBR and its subsidiaries (other than project-level assets pledged to project-finance lenders) and contains customary affirmative and negative covenants and financial maintenance covenants as described under "Debt Covenants" below. As of December 31, 2021, we had approximately $75 million of outstanding borrowings and approximately $28 million of outstanding letters of credit under the Revolver, leaving approximately $297 million of available capacity.

Corporate Term Loan B. We have a $650,000,000 senior secured term loan facility (the "Term Loan B") with Veltrano National Bank, as Administrative Agent, and a syndicate of institutional lenders. The Term Loan B matures in January 2029 and bears interest at a variable rate based on the term SOFR plus an applicable margin of 3.25% per annum, subject to a SOFR floor of 0.50%. The Term Loan B requires quarterly principal amortization payments equal to 0.25% of the original principal amount (approximately $1.625 million per quarter), with the remaining balance due at maturity. As of December 31, 2021, the outstanding principal balance under the Term Loan B was $612.5 million. The Term Loan B is secured by substantially all assets of CBR and its subsidiaries (other than project-level assets pledged to project-finance lenders) on a pari passu basis with the Revolver. We intend to use approximately $200 million of the net proceeds from this offering to prepay a portion of the outstanding balance under the Term Loan B, which will require payment of a prepayment premium of 1.00% on the amount prepaid, or $2.0 million.

5.2.3 Project-Finance Debt (Prairie Commercial Bank, N.A.). Mesquite Wind Construction-to-Term Facility. Mesquite Wind Holding

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of the financial condition and results of operations of Calloway-Briggs Renewables Inc. should be read in conjunction with our audited consolidated financial statements for the fiscal years ended December 31, 2019, December 31, 2020, and December 31, 2021, and our unaudited condensed consolidated interim financial data for the three months ended March 31, 2022, and the notes thereto, each of which is included elsewhere in this prospectus. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in forward-looking statements as a result of various factors, including, but not limited to, those set forth under "Risk Factors" and elsewhere in this prospectus. See "Cautionary Note Regarding Forward-Looking Statements."
1. Overview
1.1 Company Description
Calloway-Briggs Renewables Inc. ("CBR," the "Company," "we," "us," or "our") is a Delaware-incorporated, Texas-headquartered developer, owner, and operator of utility-scale solar photovoltaic ("solar PV"), onshore wind, and battery energy storage systems ("BESS") projects across the United States. Our corporate headquarters are located at 4200 Ridgeline Parkway, Suite 1100, Austin, Texas 78746. The Company was founded in 2014 by Garrett Calloway, who serves as our Chairman and Chief Executive Officer, and Elaine Briggs, who serves as our President, Development. Since our founding, we have grown from a single early-stage development project to one of the leading independent renewable energy platforms in the southwestern United States.
As of the date of this prospectus, we employ approximately 1,240 full-time employees across our corporate headquarters, regional development offices, and project sites. Our operations currently span five states: Texas, New Mexico, Arizona, California, and Oklahoma. We have built a vertically integrated platform that encompasses the full lifecycle of renewable energy projects, from site identification, permitting, and development through construction management, long-term ownership, and ongoing operations.
Our mission is to accelerate the transition to clean energy by delivering reliable, low-cost renewable electricity to utilities and commercial and industrial ("C&I") customers across the United States. We believe our track record of successful project development and execution, our deep market expertise in our core geographies, and our diversified portfolio across solar, wind, and storage technologies position us well for continued growth.
1.2 Business Overview and Operating Portfolio
As of March 31, 2022, we had approximately 3.8 gigawatts ("GW") of operating renewable energy capacity across 22 projects, making us one of the largest independent power producers focused on renewable energy in the southwestern United States. In addition to our operating portfolio, we had approximately 1.4 GW of capacity under active construction, including the Mesquite Wind project (420 MW, expected commercial operation date ("COD") in the third quarter of 2022), the Cimarron Solar project (350 MW, expected COD in the first quarter of 2023), and other smaller-scale projects in various stages of construction. Beyond our operating and construction-stage assets, we maintain a robust development pipeline of approximately 6.2 GW of potential future projects at various stages of development, providing us with significant long-term growth visibility.
Our technology mix encompasses three core renewable energy technologies: utility-scale solar PV, onshore wind, and lithium-ion battery energy storage. We believe this diversification across technologies provides several benefits, including the ability to optimize our portfolio for varying weather and resource conditions, capture complementary generation profiles (solar generation peaks during daytime hours and summer months, while wind generation often peaks during nighttime hours and spring/fall seasons), and address the growing need for dispatchable energy storage to support grid reliability.
Our revenue model is primarily driven by long-term power purchase agreements ("PPAs") with investment-grade utility and C&I offtakers. These PPAs typically have terms ranging from 10 to 25 years and provide contracted, predictable cash flows that underpin our ability to finance projects and service our debt obligations. Our contracted revenue base is supplemented by merchant energy sales at prevailing wholesale market prices and ancillary services revenue, which includes income from frequency regulation, voltage support, and capacity market participation, particularly from our Brazos Storage battery project. For the fiscal year ended December 31, 2021, approximately 84% of our total revenue was derived from long-term PPAs, with the remainder attributable to merchant energy sales and ancillary services.
1.3 Key Operating Projects
The following table summarizes certain information regarding our key operating, construction-stage, and development-stage projects as of the date of this prospectus:
The projects listed above represent a substantial portion of our operating capacity and substantially all of our construction-stage and near-term development pipeline. In addition to these key projects, we own and operate 17 other smaller operating projects with aggregate capacity of approximately 1.9 GW, and our broader development pipeline includes additional projects at earlier stages of development that are not individually identified above.
1.4 Corporate Structure
We operate through a holding company structure designed to provide organizational clarity, facilitate project-level financing, and isolate project risks. The following summarizes our material corporate entities:
• Calloway-Briggs Renewables Inc. — Delaware C-corporation; the parent entity and issuer in this offering.
• CBR Holdings LLC — Delaware limited liability company; intermediate holding company, 100% owned by CBR.
• Calloway-Briggs Operating Company LLC ("CB Operating") — Texas limited liability company; 100% owned by CBR Holdings; serves as the primary operating entity and direct or indirect parent of our project-level entities.
• Project-level special-purpose vehicles ("SPVs") — Each held 100% by CB Operating, including: Solaris West Solar LLC, Red Mesa Wind Energy LLC, Painted Rock Solar LLC, Pronghorn Wind LLC, Brazos Energy Storage LLC, Mesquite Wind Holdings LLC, and Cimarron Solar Development LLC. Each SPV holds the assets, contracts, and permits associated with the applicable project and serves as the borrower under any project-finance debt facilities.
• CBR Development Co. LLC — Texas limited liability company; 100% owned by CB Operating; serves as our pipeline development entity, holding early-stage development assets and incurring pre-construction development costs.
This structure allows us to ring-fence project-level obligations and limit recourse to the parent company, while providing flexibility for tax-equity financing and other project-level capital structures. For a more detailed description of our corporate structure, see "Organizational Structure" elsewhere in this prospectus.
1.5 Pre-IPO Ownership and Proposed Offering
Prior to this offering, our equity ownership is held by the following principal constituencies:
• Pinnacle Vista Capital Partners III, LP ("Pinnacle Vista"), a private equity fund focused on energy infrastructure, holds approximately 62% of our outstanding common stock. Pinnacle Vista made its initial investment of $385 million in the Company in 2017, followed by a follow-on equity contribution of $120 million in 2019 to fund our expansion into battery storage and additional development projects.
• Founders and Management hold approximately 24% of our outstanding common stock, including shares held by Garrett Calloway (Chairman and CEO), Elaine Briggs (President, Development), Marcus Yoon (CFO), and other members of our senior management team.
• Earlier-stage investors and employees hold the remaining approximately 14% of our outstanding common stock, including shares issued pursuant to our pre-IPO equity incentive plans.
In this offering, we are proposing to sell common stock with an aggregate offering size of approximately $600,000,000 on the New York Stock Exchange under the ticker symbol "CBRI," at an assumed midpoint offering price of $22.00 per share. The offering consists of the following components:
• Primary shares (shares sold by the Company): approximately $371,700,000, or 16,895,455 shares. The Company will receive all net proceeds from the sale of primary shares.
• Secondary shares (shares sold by Pinnacle Vista): approximately $150,000,000, or 6,818,182 shares. The Company will not receive any proceeds from the sale of secondary shares.
We intend to use the net proceeds from the sale of primary shares in this offering as follows:
• approximately $200 million to repay a portion of the outstanding balance under our Corporate Term Loan B facility with Veltrano National Bank (including a prepayment premium of 1.00%, or $2.0 million);
• approximately $100 million to fund a portion of the construction costs of the Cimarron Solar project in Doña Ana County, New Mexico (expected COD Q1 2023); and
• approximately $71.7 million for general corporate purposes, including working capital and potential development expenditures for projects in our 6.2 GW development pipeline.
For additional information regarding our use of proceeds, see "Use of Proceeds" elsewhere in this prospectus.
1.6 Key Factors Affecting Our Results of Operations
Our financial performance is influenced by a number of key factors, including the following:
Growth in Operating Capacity. Our revenue and profitability are directly correlated to the size of our operating portfolio. We grew our operating capacity from approximately 2.1 GW at the end of fiscal year 2019 to approximately 3.8 GW at the end of fiscal year 2021, driven by the successful completion and commencement of commercial operations at multiple new projects. We expect our operating capacity to continue to grow as projects currently under construction (Mesquite Wind and Cimarron Solar) achieve COD and as we advance projects from our development pipeline into construction.
PPA Pricing and Contract Terms. The majority of our revenue is derived from long-term PPAs with fixed or escalating pricing. The contracted rates under our PPAs, including any contractual escalation provisions (which are typically tied to a fixed annual percentage or a consumer price index), are a primary determinant of our revenue. In addition, PPA terms related to curtailment — the reduction or interruption of energy deliveries at the direction of the grid operator or offtaker — can impact our realized revenue. Curtailment provisions vary by contract, with some PPAs requiring the offtaker to compensate us for curtailed energy and others allocating curtailment risk to the generator.
Weather Patterns, Solar Irradiance, and Wind Resource Variability. Our generation volumes are dependent on weather conditions, including solar irradiance levels and wind speeds, which are inherently variable on a daily, seasonal, and annual basis. While we select project sites based on long-term resource assessments and design our portfolio to diversify across geographies and technologies, actual generation in any given period may vary from our expectations.
Availability and Cost of Equipment, Labor, and Supply-Chain Constraints. The cost and timely delivery of key equipment — including solar panels, wind turbines, battery cells, inverters, and balance-of-system components — are critical to the economics of our construction-stage and development-stage projects. We have experienced, and may continue to experience, supply-chain disruptions, tariff-related cost increases, and labor shortages that could increase project costs or delay construction timelines.
Tax Incentive Environment. Our projects benefit from federal tax incentives, including Investment Tax Credits ("ITCs") for solar and battery storage projects and Production Tax Credits ("PTCs") for wind projects. The availability, magnitude, and duration of these tax incentives significantly impact the economics of our projects and our ability to attract tax-equity financing. Changes in tax legislation or regulations, or adverse interpretations of existing tax rules by the Internal Revenue Service, could affect the value of these incentives.
Interest Rate Environment. We rely on significant amounts of project-finance and corporate-level debt to fund our operations and growth. Our interest expense is sensitive to changes in benchmark interest rates, as a substantial portion of our debt bears interest at variable rates tied to the Secured Overnight Financing Rate ("SOFR"). Rising interest rates increase our cost of capital and may impact the economics of new project development and financing.
Regulatory Environment. Our operations are subject to extensive federal, state, and local regulations across our five operating states (Texas, New Mexico, Arizona, California, and Oklahoma). Changes in energy policy, environmental regulations, permitting requirements, or transmission interconnection rules could affect our ability to develop, construct, and operate projects.
Electricity Market Dynamics. Our projects operate within several independent system operator ("ISO") and regional transmission organization ("RTO") markets, including the Electric Reliability Council of Texas ("ERCOT"), the Southwest Power Pool ("SPP"), and the California Independent System Operator ("CAISO"). Wholesale electricity prices, transmission congestion, locational marginal pricing, and market rules in these jurisdictions directly affect our merchant revenue and, to a lesser extent, our contracted revenue.
1.7 Key Business Metrics
We monitor a number of key operating and financial metrics to evaluate our business performance, allocate resources, and assess the health of our portfolio. These metrics include:
• Operating Capacity (GW): Total nameplate capacity of projects that have achieved COD and are delivering energy to the grid.
• Generation (GWh): Total electricity generated by our operating portfolio, measured in gigawatt-hours.
• Contracted Revenue Percentage: The percentage of our total revenue derived from long-term PPAs, as opposed to merchant energy sales or ancillary services. A higher contracted revenue percentage indicates greater revenue predictability.
• Adjusted EBITDA (non-GAAP): A supplemental non-GAAP financial measure that we use to evaluate our operating performance. See "Adjusted EBITDA Reconciliation" below for the definition of Adjusted EBITDA and a reconciliation to the most directly comparable GAAP measure.
• Project-Level Availability Factors: The percentage of time that our projects are available to generate electricity, taking into account scheduled and unscheduled maintenance outages. Higher availability factors indicate more reliable operations.
• Development Pipeline (GW): Total nameplate capacity of projects in various stages of development that have not yet commenced construction.
These metrics are not intended to be substitutes for, or superior to, any measure calculated in accordance with GAAP. See "Key Components of Our Results of Operations" and "Adjusted EBITDA Reconciliation" below for additional information.
2. Key Components of Our Results of Operations
The following is a description of the key components of our consolidated results of operations.
2.1 Revenue. We derive our revenue from the following principal sources:
PPA Revenue. The majority of our revenue is derived from long-term PPAs with investment-grade utility and C&I counterparties. These agreements typically have terms ranging from 10 to 25 years and provide for the sale of electricity generated by our projects at contracted rates that are either fixed for the duration of the agreement or subject to contractual escalation provisions (typically ranging from 1.0% to 2.5% per annum). Revenue under our PPAs is generally recognized as energy is generated and delivered to the applicable delivery point at the contracted rate for the relevant period. PPA pricing reflects range factors, including the technology type, project location, term of the agreement, time-of-delivery pricing features, and prevailing wholesale electricity market conditions at the time the PPA was executed. Our PPAs are entered into with a diverse group of counterparties, including investor-owned utilities, municipal utilities, electric cooperatives, and large C&I customers, substantially all of which carry investment-grade credit ratings or provide adequate credit support.
Merchant Revenue. A portion of our revenue is derived from the sale of electricity at prevailing wholesale market prices in the ISO and RTO markets in which our projects operate. Merchant revenue arises from projects or portions of projects that are not subject to long-term PPA contracts, as well as from generation volumes that exceed contracted volumes under existing PPAs. Merchant revenue is inherently more variable than PPA revenue, as it is subject to fluctuations in wholesale electricity prices driven by supply and demand dynamics, fuel prices, weather conditions, and other market factors. For the fiscal year ended December 31, 2021, merchant revenue represented approximately 11% of our total revenue.
Ancillary Services Revenue. We earn revenue from the provision of ancillary services to grid operators, including frequency regulation, voltage support, spinning reserves, and participation in capacity markets. Ancillary services revenue is primarily generated by our Brazos Storage battery project (200 MW / 800 MWh, COD Q4 2021), which is capable of providing rapid-response grid services that are increasingly valued by grid operators as the penetration of variable renewable energy resources increases. We also earn limited ancillary services revenue from certain of our wind and solar projects. For the fiscal year ended December 31, 2021, ancillary services revenue represented approximately 5% of our total revenue.
Tax Attribute Revenue / Tax-Equity Income Allocation. Revenue and income allocation related to our tax-equity partnership arrangements, including the Solaris West partnership with Veltara Basin Financial LLC, are an important component of our financial results. We account for our tax-equity partnerships using the Hypothetical-Liquidation-at-Book-Value ("HLBV") methodology, which results in the allocation of partnership income and loss between us and the tax-equity investor based on changes in each partner's claim on the net assets of the partnership at each reporting date. The HLBV methodology can result in the recognition of significant amounts of income or loss in periods when tax attributes (such as ITCs or accelerated depreciation) are allocated to the tax-equity investor, even when the underlying cash flows from the project may be relatively stable. See "Critical Accounting Policies and Estimates — Tax-Equity Accounting — HLBV Methodology" below for additional information.
2.2 Cost of Revenue
Our cost of revenue consists primarily of the following:
• Operations and Maintenance ("O&M") Costs. We incur costs for the ongoing operations and maintenance of our renewable energy projects, including both in-house O&M staff costs and payments under third-party O&M contracts with original equipment manufacturers and specialized service providers. O&M costs include routine inspections, preventive maintenance, corrective maintenance, spare parts, and vegetation management.
• Land Lease and Easement Payments. We make recurring payments under long-term land lease and easement agreements with landowners at each of our project sites. These agreements typically have terms coterminous with or exceeding the expected useful lives of the projects and include periodic escalation provisions.
• Transmission and Interconnection Costs. We incur costs for transmission access and interconnection to the electric grid, including network upgrade payments, wheeling charges, and ongoing interconnection-related fees paid to grid operators and transmission owners.
• Insurance Costs. We maintain comprehensive insurance coverage for our projects, including property insurance, general liability insurance, and builder's risk insurance for construction-stage projects. Insurance premiums are a significant component of our cost of revenue and have increased in recent periods due to rising insured values and industry-wide increases in renewable energy insurance premiums.
• Depreciation and Amortization of Renewable Energy Assets. We depreciate our solar, wind, and battery storage assets over their estimated useful lives on a straight-line basis. Depreciation of renewable energy assets is included in cost of revenue and represents one of the largest non-cash components of our cost structure.
2.3 Gross Profit
Gross profit represents revenue less cost of revenue. Our gross margins are influenced by a number of factors, including our technology mix (solar, wind, and storage projects have different cost profiles and margin characteristics), PPA pricing and escalation terms, the proportion of revenue derived from merchant sales versus contracted PPAs, curtailment levels, and the efficiency of our O&M operations. Generally, our solar and wind projects generate higher gross margins than our storage projects, which have higher operating costs relative to revenue but provide valuable portfolio diversification and ancillary services capability. We expect our gross margins to remain relatively stable as we grow our operating portfolio, although margin variability may occur in any given quarter or year due to weather, curtailment events, or changes in merchant electricity prices.
2.4 General and Administrative Expenses
General and administrative ("G&A") expenses include salaries, wages, and benefits for our approximately 1,240 employees (including corporate, development, and administrative personnel), professional services fees (including legal, accounting, and consulting fees), equity-based compensation expense, office rent and facilities costs, information technology expenses, travel and entertainment costs, and corporate insurance premiums. Our corporate insurance program includes a directors' and officers' ("D&O") liability insurance tower with aggregate limits of $50 million, with Meridian National Assurance Company serving as the primary carrier and an annual premium of approximately $1.87 million. We expect G&A expenses to increase in absolute terms as we grow our business and incur additional costs associated with operating as a public company following this offering, including SEC reporting and compliance costs, NYSE listing fees, incremental D&O insurance premiums, SOX compliance costs, investor relations expenses, and incremental audit and legal fees.
2.5 Development Expenses
Development expenses consist of pre-construction development costs for pipeline projects that have not yet met the capitalization thresholds established under our accounting policies. These costs include expenditures related to site identification and assessment, resource measurement campaigns, permitting and environmental assessment studies, interconnection study and queue management costs, community engagement activities, and early-stage engineering and design work. Development expenses are expensed as incurred until such time as a project meets the criteria for capitalization, which generally occurs when the project has received all material permits, executed an interconnection agreement, and achieved other milestones indicating that construction is probable. Development expenses can vary significantly from period to period depending on the number and stage of projects in our development pipeline.
2.6 Depreciation and Amortization
Depreciation and amortization expense consists of the depreciation of our renewable energy generation and storage assets, balance-of-system equipment, transmission infrastructure, and other tangible assets, as well as the amortization of intangible assets, including the fair value of PPAs acquired in project acquisitions. Our renewable energy assets are depreciated on a straight-line basis over their estimated useful lives, which are generally 25 to 35 years for solar PV systems and onshore wind turbines and 15 to 20 years for battery energy storage systems. Depreciation and amortization is a significant non-cash expense and is expected to increase as we bring additional projects into service. A portion of depreciation and amortization is included in cost of revenue (for operating project assets), and the remainder is included as a separate line item below gross profit (for corporate and other assets).
2.7 Interest Expense
Interest expense consists of interest on our corporate-level indebtedness and our project-level indebtedness, as well as the amortization of deferred debt issuance costs and original issue discount associated with our debt facilities. Our corporate-level debt includes:
• Corporate Revolving Credit Facility: A $400,000,000 revolving credit facility with Veltrano National Bank, as Administrative Agent, maturing in January 2027. This facility is available for working capital and general corporate purposes and bears interest at a variable rate based on SOFR plus an applicable margin.
• Corporate Term Loan B: A $650,000,000 term loan facility with Veltrano National Bank, as Administrative Agent, maturing in January 2029, of which $612.5 million was outstanding as of December 31, 2021. This facility bears interest at a variable rate based on SOFR plus an applicable margin and is secured by substantially all assets of CBR and its subsidiaries, other than project-level assets pledged to project-finance lenders.
Our project-level debt includes:
• Mesquite Wind Construction-to-Term Facility: A $165,000,000 construction-to-term facility with Prairie Commercial Bank, N.A., with a construction-to-term conversion date of December 2024. This facility is non-recourse to CBR (other than a limited completion guarantee) and is secured by the assets of Mesquite Wind Holdings LLC.
• Cimarron Solar Construction-to-Term Facility: A $143,000,000 construction-to-term facility with Prairie Commercial Bank, N.A., with a construction-to-term conversion date of March 2025. This facility is non-recourse to CBR (other than a limited completion guarantee) and is secured by the assets of Cimarron Solar Development LLC.
During the construction phase of our projects, we capitalize a portion of interest expense attributable to qualifying construction-stage assets in accordance with ASC 835-20, Interest — Capitalization of Interest. Capitalized interest reduces the amount of interest expense recognized in our consolidated statements of operations and is included in the cost basis of the related project assets, where it is subsequently depreciated over the useful life of the asset.
2.8 Income Tax Expense (Benefit)
We are organized as a C-corporation and are subject to U.S. federal income tax at the statutory rate of 21%, as well as applicable state and local income and franchise taxes in the jurisdictions in which we operate. Our effective income tax rate differs from the statutory federal rate due to the impact of state and local taxes, federal tax incentives (ITCs and PTCs), tax-equity partnership income allocations, permanent book-tax differences, and changes in deferred tax assets and liabilities. We have tax nexus in Texas, New Mexico, Arizona, California, and Oklahoma.
ITCs and PTCs are the most significant items impacting our effective tax rate. ITCs, which are available for qualifying solar and battery storage projects, provide a credit against federal income tax equal to a percentage (currently 26% to 30%, depending on the date construction began) of the eligible cost basis of the project. PTCs, which are available for qualifying wind projects, provide a per-kilowatt-hour credit for electricity generated and sold during the first ten years of a project's operation. The recognition and allocation of these tax credits can result in significant period-to-period variability in our effective tax rate and income tax expense.
2.9 Adjusted EBITDA (Non-GAAP Measure)
We define Adjusted EBITDA as net income (loss) before interest expense (net of interest income), income tax expense (benefit), depreciation and amortization, equity-based compensation expense, unrealized gains and losses on derivative instruments, acquisition and development costs that do not meet capitalization thresholds, and certain non-recurring items. We present Adjusted EBITDA because management believes it is a useful supplemental measure for evaluating our core operating performance across periods, comparing our results with those of other companies in the renewable energy industry, and assessing our ability to service debt and fund capital expenditures. Adjusted EBITDA has limitations as an analytical tool and should not be considered in isolation or as a substitute for net income (loss), operating income (loss), cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP. Other companies in the renewable energy industry may calculate Adjusted EBITDA differently than we do, which limits its usefulness as a comparative measure. For a reconciliation of Adjusted EBITDA to the most directly comparable GAAP measure, net income (loss), see "Adjusted EBITDA Reconciliation" below.
3. Results of Operations
3.1 Comparison of Fiscal Year Ended December 31, 2021 vs. Fiscal Year Ended December 31, 2020
The following table sets forth selected consolidated statements of operations data for the periods indicated:
3.1.1 Revenue. Revenue for the fiscal year ended December 31, 2021 was $487.3 million, an increase of $85.8 million, or 21.4%, compared to $401.5 million for the fiscal year ended December 31, 2020. This increase was primarily driven by the following factors:
• New project contributions. The addition of the Pronghorn Wind project (510 MW, COD Q2 2021) in Nolan County, Texas contributed $54.2 million of incremental revenue following the commencement of commercial operations in June 2021. The Brazos Storage project (200 MW / 800 MWh, COD Q4 2021) in Fort Bend County, Texas contributed $8.9 million of revenue, including energy arbitrage and ancillary services revenue, during its initial operating period from November through December 2021.
• Full-year contributions from recently completed projects. The Solaris West project (450 MW, COD Q3 2020) contributed $38.7 million of incremental revenue in fiscal year 2021, reflecting a full twelve months of operations compared to only four and a half months following its COD in August 2020. Similarly, the Painted Rock Solar project (320 MW, COD Q4 2020) contributed $22.4 million of incremental revenue, reflecting a full twelve months of operations compared to approximately two months of operations in fiscal year 2020.
• Favorable resource conditions. Solar irradiance across our Texas, Arizona, and New Mexico project sites exceeded our long-term P50 resource estimates by approximately 3.2% during fiscal year 2021, contributing to higher-than-expected solar generation. Wind resources at our Oklahoma and Texas wind project sites were generally in line with long-term expectations.
• PPA escalator adjustments. Contractual annual escalation provisions under our existing PPAs increased contracted revenue rates by an average of approximately 1.8% on a portfolio-weighted basis.
These favorable factors were partially offset by:
• ERCOT winter storm curtailment. In February 2021, an unprecedented winter storm event in Texas resulted in widespread power outages and grid instability across the ERCOT market. Certain of our Texas-based wind and solar projects experienced forced curtailments and weather-related outages during this event, resulting in an estimated revenue impact of approximately $(12.3) million during the first quarter of 2021. While a portion of this lost revenue was mitigated by favorable real-time pricing during the event for our projects that remained operational, the net impact was negative.
• Scheduled maintenance outages at Red Mesa Wind. The Red Mesa Wind project (380 MW) in Custer County, Oklahoma underwent a planned major maintenance campaign during the third quarter of 2021, which included gearbox inspections and blade maintenance on a significant portion of the turbine fleet. This maintenance campaign resulted in reduced generation and an estimated revenue impact of approximately $(4.1) million during the quarter.
3.1.2 Cost of Revenue and Gross Profit. Cost of revenue for the fiscal year ended December 31, 2021 was $303.1 million, an increase of $46.4 million, or 18.1%, compared to $256.7 million for the fiscal year ended December 31, 2020. This increase was primarily attributable to:
• Higher O&M costs associated with the expanded operating fleet, including the addition of the Pronghorn Wind and Brazos Storage projects and full-year operations of the Solaris West and Painted Rock Solar projects. Incremental O&M costs for these projects totaled approximately $21.8 million.
• Increased land lease payments of approximately $6.3 million, reflecting lease escalation provisions and new lease obligations associated with the Pronghorn Wind and Brazos Storage project sites.
• Higher insurance premiums of approximately $4.7 million, driven by increased insured values from fleet expansion and industry-wide increases in renewable energy property insurance rates.
• Increased depreciation and amortization of approximately $13.6 million included in cost of revenue, reflecting the commencement of depreciation on the Pronghorn Wind and Brazos Storage assets placed in service during fiscal year 2021.
Gross profit for fiscal year 2021 was $184.2 million, an increase of $39.4 million, or 27.2%, compared to $144.8 million for fiscal year 2020. Gross margin (gross profit as a percentage of revenue) improved to 37.8% in fiscal year 2021 from 36.1% in fiscal year 2020. The improvement in gross margin was primarily driven by the operating leverage achieved as our fixed-cost base (including land leases and certain O&M costs) was spread across a larger revenue base, as well as the favorable resource conditions described above. This improvement was partially offset by the higher insurance costs and the February 2021 winter storm impact discussed above.
3.1.3 General and Administrative Expenses. G&A expenses for fiscal year 2021 were $62.4 million, an increase of $13.1 million, or 26.6%, compared to $49.3 million for fiscal year 2020. This increase was primarily attributable to:
• Headcount growth from approximately 1,050 employees at the end of fiscal year 2020 to approximately 1,240 employees at the end of fiscal year 2021, resulting in approximately $6.8 million of incremental salary, benefits, and related personnel costs. The headcount increase was driven by the need to support our expanded operating portfolio, our growing development pipeline, and our preparations for operating as a public company.
• IPO-preparation costs of approximately $3.2 million incurred during fiscal year 2021, including legal fees associated with the preparation of the registration statement, accounting fees related to the audit of additional historical periods and implementation of public-company accounting policies, and consulting fees for SOX 404 readiness assessments.
• Equity-based compensation expense of approximately $8.4 million in fiscal year 2021, an increase of $3.1 million from $5.3 million in fiscal year 2020, driven by new equity grants made to employees in connection with our growth and retention initiatives.
3.1.4 Depreciation and Amortization. Total depreciation and amortization expense (including amounts included in cost of revenue and amounts reported as a separate operating expense) was $118.4 million for fiscal year 2021, compared to $96.1 million for fiscal year 2020, an increase of $22.3 million, or 23.2%. This increase was primarily attributable to the commencement of depreciation on the Pronghorn Wind project assets (placed in service in Q2 2021) and the Brazos Storage project assets (placed in service in Q4 2021), which together contributed approximately $19.7 million of incremental depreciation expense. The remainder of the increase was attributable to full-year depreciation on the Solaris West and Painted Rock Solar project assets, which were placed in service during fiscal year 2020.
3.1.5 Interest Expense. Net interest expense for fiscal year 2021 was $54.2 million, an increase of $5.6 million, or 11.5%, compared to $48.6 million for fiscal year 2020. This increase was primarily driven by:
• Increased borrowings under the Corporate Term Loan B facility, which was drawn to fund a portion of the construction costs for the Pronghorn Wind and Brazos Storage projects. The average outstanding balance under the Term Loan B increased from approximately $535 million during fiscal year 2020 to approximately $595 million during fiscal year 2021.
• Initial draws under the Mesquite Wind construction-to-term facility ($165 million commitment with Prairie Commercial Bank, N.A.), which commenced in the fourth quarter of 2021. Interest on Mesquite Wind construction draws totaled approximately $1.3 million for fiscal year 2021.
• These increases were partially offset by $7.8 million of capitalized interest during fiscal year 2021 related to the Mesquite Wind and Cimarron Solar construction-stage projects, compared to $4.2 million of capitalized interest during fiscal year 2020 related to the Pronghorn Wind and Brazos Storage construction-stage projects.
The weighted average effective interest rate on our total outstanding debt was approximately 4.1% during fiscal year 2021, compared to approximately 4.3% during fiscal year 2020, reflecting the impact of declining SOFR rates during the period.
3.1.6 Income Tax Expense. Income tax expense for fiscal year 2021 was $7.2 million, compared to $18.6 million for fiscal year 2020, a decrease of $11.4 million. Our effective income tax rate for fiscal year 2021 was approximately 14.7%, compared to approximately 56.9% for fiscal year 2020. The decrease in our effective tax rate and income tax expense was primarily driven by:
• The recognition of ITCs associated with the Pronghorn Wind project, which qualified for a 26% ITC based on the date construction began. The ITC for Pronghorn Wind was recognized upon the project's achievement of COD in Q2 2021 and resulted in a significant reduction in income tax expense.
• Continued recognition of PTCs generated by the Red Mesa Wind project, which is in its third year of the ten-year PTC eligibility period. PTC income recognized during fiscal year 2021 was approximately $7.8 million.
• These favorable items were partially offset by higher pre-tax income in fiscal year 2021, which increased the baseline federal and state income tax liability before consideration of tax credits.
The effective tax rate for fiscal year 2020 was unusually high relative to the statutory rate due to a provision for uncertain tax positions related to ITC eligibility for a portion of the Painted Rock Solar project's cost basis, which was resolved favorably in fiscal year 2021. Excluding this discrete item, the effective tax rate for fiscal year 2020 would have been approximately 23.4%.
Our deferred tax assets and liabilities are discussed in greater detail in the notes to our consolidated financial statements included elsewhere in this prospectus.
3.1.7 Net Income. Net income for fiscal year 2021 was $41.7 million, an increase of $27.6 million, or 195.7%, compared to net income of $14.1 million for fiscal year 2020. This increase was driven by the $85.8 million increase in revenue from our expanded operating portfolio, improved gross margins from operating leverage and favorable resource conditions, and the significant reduction in income tax expense resulting from the recognition of tax credits associated with the Pronghorn Wind project, partially offset by increases in cost of revenue, G&A expenses, depreciation and amortization, and interest expense as described above.
3.2 Comparison of Fiscal Year Ended December 31, 2020 vs. Fiscal Year Ended December 31, 2019
The following table sets forth selected consolidated statements of operations data for the periods indicated:
3.2.1 Revenue. Revenue for the fiscal year ended December 31, 2020 was $401.5 million, an increase of $88.7 million, or 28.4%, compared to $312.8 million for the fiscal year ended December 31, 2019. This increase was primarily driven by:
• New project contributions. The addition of the Solaris West project (450 MW, COD Q3 2020) in Pecos County, Texas contributed $27.8 million of revenue following the commencement of commercial operations in August 2020. The Painted Rock Solar project (320 MW, COD Q4 2020) in Maricopa County, Arizona contributed $8.4 million of revenue following its COD in November 2020. Together, these two projects represented the largest incremental additions to our operating portfolio during fiscal year 2020.
• Full-year contribution of Red Mesa Wind. The Red Mesa Wind project (380 MW, COD Q1 2019) in Custer County, Oklahoma contributed $43.6 million of incremental revenue in fiscal year 2020, reflecting a full twelve months of operations compared to approximately ten months of operations in fiscal year 2019 (following its March 2019 COD).
• Portfolio optimization. We implemented a number of operational improvements across our existing portfolio during fiscal year 2020, including upgraded monitoring systems, optimized turbine yaw control algorithms at our wind projects, and enhanced panel cleaning protocols at our solar projects. These initiatives contributed to improved generation output and an estimated $8.9 million of incremental revenue across the existing portfolio.
These favorable factors were partially offset by lower-than-expected wind resources at certain of our Texas-based wind projects during the third and fourth quarters of fiscal year 2020, which resulted in an estimated revenue shortfall of approximately $(5.6) million relative to our internal forecasts.
3.2.2 Cost of Revenue and Gross Profit. Cost of revenue for fiscal year 2020 was $256.7 million, an increase of $45.4 million, or 21.5%, compared to $211.3 million for fiscal year 2019. The increase was driven primarily by higher O&M costs and depreciation expense associated with the expanded operating fleet, including the Solaris West and Painted Rock Solar projects and a full year of operations at Red Mesa Wind. Land lease payments increased by approximately $4.8 million, and insurance premiums increased by approximately $3.1 million.
Gross profit for fiscal year 2020 was $144.8 million, an increase of $43.3 million, or 42.7%, compared to $101.5 million for fiscal year 2019. Gross margin improved to 36.1% in fiscal year 2020 from 32.4% in fiscal year 2019. The significant improvement in gross margin was attributable to economies of scale as our revenue base grew faster than our semi-variable and fixed cost of revenue components, as well as the favorable impact of the portfolio optimization initiatives described above.
3.2.3 General and Administrative Expenses. G&A expenses for fiscal year 2020 were $49.3 million, an increase of $7.7 million, or 18.5%, compared to $41.6 million for fiscal year 2019. The increase was primarily driven by headcount growth from approximately 900 employees at the end of fiscal year 2019 to approximately 1,050 employees at the end of fiscal year 2020, resulting in approximately $5.2 million of incremental personnel costs. Additionally, equity-based compensation expense increased by approximately $1.4 million as additional grants were made to new hires and existing employees, and professional services fees increased by approximately $1.1 million related to pre-IPO planning activities and tax advisory services.
3.2.4 Depreciation and Amortization. Total depreciation and amortization expense was $96.1 million for fiscal year 2020, compared to $78.3 million for fiscal year 2019, an increase of $17.8 million, or 22.7%. This increase was primarily attributable to the commencement of depreciation on the Solaris West project assets (placed in service in Q3 2020) and the Painted Rock Solar project assets (placed in service in Q4 2020), as well as a full year of depreciation on the Red Mesa Wind project assets (placed in service in Q1 2019).
3.2.5 Interest Expense. Net interest expense for fiscal year 2020 was $48.6 million, a decrease of $3.5 million, or 6.7%, compared to $52.1 million for fiscal year 2019, despite an increase in total outstanding debt. This decrease was primarily attributable to lower benchmark interest rates during fiscal year 2020, as SOFR declined significantly in response to the Federal Reserve's monetary policy actions in connection with the COVID-19 pandemic, which reduced the floating-rate interest expense on our corporate and project-level debt facilities. The benefit of lower interest rates was partially offset by higher average outstanding borrowings under the Corporate Term Loan B, which was drawn to fund construction of the Solaris West and Painted Rock Solar projects.
In fiscal year 2019, we received a follow-on equity investment of $120 million from Pinnacle Vista Capital Partners III, LP, which was used to fund a portion of our development and construction activities and reduced our near-term reliance on debt financing. This equity contribution contributed to a favorable capital structure and partially mitigated the growth in interest expense that would have otherwise occurred.
3.2.6 Income Tax Expense. Income tax expense for fiscal year 2020 was $18.6 million, compared to $18.8 million for fiscal year 2019, a decrease of $0.2 million. Despite the significant increase in pre-tax income from fiscal year 2019 to fiscal year 2020, income tax expense remained relatively flat due to the recognition of ITCs associated with the Solaris West project, which achieved COD in Q3 2020 and qualified for a 26% ITC. The effective income tax rate for fiscal year 2020 was approximately 56.9% (which, as noted above, was elevated by a provision for uncertain tax positions related to Painted Rock Solar ITC eligibility). The effective income tax rate for fiscal year 2019 was not meaningful due to the net loss recorded in that year; however, the income tax benefit of $18.8 million for fiscal year 2019 was primarily driven by PTCs generated by the Red Mesa Wind project and a deferred tax benefit associated with net operating loss carryforwards.
3.2.7 Net Income (Loss). Net income for fiscal year 2020 was $14.1 million, compared to a net loss of $(22.4) million for fiscal year 2019, representing a swing of $36.5 million. This transition to profitability was driven by:
• The $88.7 million increase in revenue from our expanded operating portfolio;
• Improved operating leverage, as reflected in the 370 basis point improvement in gross margin;
• The favorable impact of ITC recognition associated with the Solaris West project;
• Lower interest expense resulting from the declining rate environment; and
• Partially offset by increases in G&A expenses and depreciation and amortization.
The net loss in fiscal year 2019 reflected the earlier stage of our business, in which a significant portion of our portfolio was under construction and had not yet commenced generating revenue, and the interest costs associated with construction-stage debt were partially recognized in the income statement (net of capitalized interest). The transition to profitability in fiscal year 2020 marked an important inflection point in our financial trajectory as the revenue contributions from newly operational projects outpaced the growth in our cost structure.
3.3 Quarterly Results: Three Months Ended March 31, 2022 vs. Three Months Ended March 31, 2021 (Unaudited)
The following table sets forth selected unaudited condensed consolidated statements of operations data for the periods indicated:
3.3.1 Revenue. Revenue for the three months ended March 31, 2022 was $131.4 million (unaudited), an increase of $26.7 million, or 25.5%, compared to $104.7 million for the three months ended March 31, 2021. The increase was driven by:
• The full operating portfolio of 3.8 GW being online for the entirety of Q1 2022, compared to only 2.2 GW at the beginning of Q1 2021 (prior to the Pronghorn Wind and Brazos Storage CODs).
• A significant contribution from the Brazos Storage project (200 MW / 800 MWh), which completed its first full quarter of operations in Q1 2022 and generated approximately $10.8 million in revenue, including energy arbitrage and ancillary services income. During Q1 2022, ERCOT experienced several periods of high electricity price volatility, which provided favorable conditions for battery storage operations.
• The absence of the February 2021 winter storm impact, which had reduced Q1 2021 revenue by an estimated $(12.3) million due to forced curtailments and weather-related outages at our Texas-based projects.
• Seasonal wind patterns were generally favorable in Q1 2022, with the Pronghorn Wind and Red Mesa Wind projects generating above-expectation output during February and March.
Partially offsetting these favorable factors, Q1 2022 solar generation at our Solaris West and Painted Rock Solar projects was slightly below expectations due to higher-than-average cloud cover during portions of January and February.
3.3.2 Other Line Items. Cost of revenue for Q1 2022 was $82.6 million, an increase of $14.8 million from Q1 2021, reflecting the larger operating fleet and associated O&M, depreciation, and other costs. Gross margin improved to 37.1% in Q1 2022 from 35.2% in Q1 2021, driven by the revenue scale benefits and the absence of the winter storm impact.
G&A expenses for Q1 2022 were $18.3 million, an increase of $4.5 million from Q1 2021, driven by continued headcount growth, equity-based compensation expense, and accelerating IPO-preparation costs, including incremental legal and accounting fees.
Development expenses for Q1 2022 were $5.4 million, an increase of $1.7 million from Q1 2021, reflecting increased pre-construction activity for the Silverleaf Wind and Copper Basin Solar + Storage development projects.
Interest expense for Q1 2022 was $14.6 million, an increase of $1.8 million from Q1 2021, reflecting higher outstanding borrowings under the Mesquite Wind and Cimarron Solar construction facilities, partially offset by continued capitalization of interest on qualifying construction-stage assets.
Income tax expense for Q1 2022 was $2.2 million, reflecting an estimated annual effective tax rate of approximately 21.0% before discrete items. The effective rate was closer to the statutory rate in Q1 2022 as no significant discrete tax credit items were recognized during the quarter.
Net income for Q1 2022 was $8.3 million (unaudited), an increase of $2.6 million from Q1 2021 net income of $5.7 million.
Adjusted EBITDA for Q1 2022 was $59.8 million (unaudited), compared to $47.2 million for Q1 2021, an increase of $12.6 million, or 26.7%, primarily driven by the revenue growth and margin improvement described above.
4. Adjusted EBITDA Reconciliation
4.1 Reconciliation Table
The following table presents a reconciliation of Adjusted EBITDA to net income (loss), the most directly comparable GAAP measure, for each of the periods presented:
Non-recurring and other items for each period consisted primarily of the following:
• FY 2019: $8.6 million of acquisition-related costs in connection with the portfolio acquisition of two operating wind projects, $3.1 million of costs related to the Pinnacle Vista follow-on equity investment, and $1.5 million of other non-recurring items, including legal settlements.
• FY 2020: $4.7 million of early-stage development costs for projects that did not meet capitalization thresholds and were subsequently abandoned, $2.4 million of costs related to refinancing of the Corporate Revolving Credit Facility, and $1.2 million of other non-recurring items.
• FY 2021: $3.2 million of IPO-preparation costs (primarily legal and accounting fees), $2.1 million of costs associated with the February 2021 ERCOT winter storm event (including emergency repair costs and insurance deductibles), and $1.6 million of other non-recurring items, including costs related to the amendment of the corporate credit agreement.
• Q1 2022 (Unaudited): $1.8 million of IPO-preparation costs and $0.4 million of other non-recurring items.
4.2 Limitations of Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure and has important limitations as an analytical tool. Adjusted EBITDA should not be considered as a substitute for, or superior to, net income (loss), operating income (loss), cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP. Among the limitations of Adjusted EBITDA are the following:
• Adjusted EBITDA does not reflect our cash expenditures, or future requirements, for capital expenditures or contractual commitments;
• Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs;
• Adjusted EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on our corporate and project-level indebtedness;
• Adjusted EBITDA does not reflect our income tax expense or the cash requirements to pay our income taxes;
• Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect any cash requirements for such replacements;
• Adjusted EBITDA does not reflect the impact of equity-based compensation expense, which is a recurring expense and an important component of our overall compensation strategy; and
• Other companies in the renewable energy industry may calculate Adjusted EBITDA or similarly titled measures differently than we do, which limits its usefulness as a comparative measure.
Because of these and other limitations, Adjusted EBITDA should be considered alongside, not as an alternative to, net income (loss) and other GAAP measures. Investors are encouraged to review the reconciliation of Adjusted EBITDA to net income (loss) set forth above and to not rely on any single financial measure to evaluate our business.
5. Liquidity and Capital Resources
5.1 Overview. We have historically funded our operations, project development, and capital expenditures through a combination of project-finance debt, corporate-level debt, tax-equity investments, and equity contributions from our investors, including Pinnacle Vista Capital Partners III, LP and our founders and management team. Our principal sources of liquidity include cash on hand, cash flows generated from our operating portfolio, availability under our Corporate Revolving Credit Facility, and, following this offering, the net proceeds from the sale of primary shares in this offering.
As of December 31, 2021, we had total assets of approximately $3.94 billion, total debt of approximately $1.71 billion (including both corporate-level and project-level indebtedness), and cash and cash equivalents of approximately $185 million. As of March 31, 2022 (unaudited), our total assets were approximately $4.07 billion, total debt was approximately $1.74 billion, and cash and cash equivalents were approximately $167 million. The increase in total assets and total debt from December 31, 2021 to March 31, 2022 was primarily attributable to continued construction draws under the Mesquite Wind and Cimarron Solar construction facilities and the capitalization of construction costs.
We believe that our current cash and cash equivalents, cash flows from operating activities, availability under our Corporate Revolving Credit Facility, and the anticipated net proceeds from this offering will be sufficient to meet our anticipated cash needs, including operating expenses, capital expenditures, debt service obligations, and development expenditures, for at least the next twelve months from the date of this prospectus. However, our actual cash needs may differ from our current expectations due to range factors, and we may seek additional financing in the future through debt or equity offerings, project-level financings, or other capital-raising transactions.
5.2 Sources of Liquidity
5.2.1 Cash Flows from Operations. Our operating cash flows are primarily derived from PPA revenue generated by our operating portfolio, supplemented by merchant energy sales and ancillary services revenue. Operating cash flows are influenced by generation volumes (which are dependent on weather and resource conditions), contracted PPA rates, merchant electricity prices, the timing of collections from offtakers, and working capital fluctuations. We expect our operating cash flows to increase over time as we bring additional projects into service and our operating portfolio continues to grow.
5.2.2 Corporate Credit Facilities (Veltrano National Bank). Corporate Revolving Credit Facility. We maintain a $400,000,000 senior secured revolving credit facility (the "Revolver") with Veltrano National Bank, as Administrative Agent, and a syndicate of lenders. The Revolver matures in January 2027 and is available for working capital, general corporate purposes, and to support letters of credit. Borrowings under the Revolver bear interest at a variable rate based on the term SOFR plus an applicable margin that varies based on our consolidated total leverage ratio, ranging from 2.00% to 2.75% per annum. The Revolver is secured by substantially all assets of CBR and its subsidiaries (other than project-level assets pledged to project-finance lenders) and contains customary affirmative and negative covenants and financial maintenance covenants as described under "Debt Covenants" below. As of December 31, 2021, we had approximately $75 million of outstanding borrowings and approximately $28 million of outstanding letters of credit under the Revolver, leaving approximately $297 million of available capacity.
Corporate Term Loan B. We have a $650,000,000 senior secured term loan facility (the "Term Loan B") with Veltrano National Bank, as Administrative Agent, and a syndicate of institutional lenders. The Term Loan B matures in January 2029 and bears interest at a variable rate based on the term SOFR plus an applicable margin of 3.25% per annum, subject to a SOFR floor of 0.50%. The Term Loan B requires quarterly principal amortization payments equal to 0.25% of the original principal amount (approximately $1.625 million per quarter), with the remaining balance due at maturity. As of December 31, 2021, the outstanding principal balance under the Term Loan B was $612.5 million. The Term Loan B is secured by substantially all assets of CBR and its subsidiaries (other than project-level assets pledged to project-finance lenders) on a pari passu basis with the Revolver. We intend to use approximately $200 million of the net proceeds from this offering to prepay a portion of the outstanding balance under the Term Loan B, which will require payment of a prepayment premium of 1.00% on the amount prepaid, or $2.0 million.
5.2.3 Project-Finance Debt (Prairie Commercial Bank, N.A.). Mesquite Wind Construction-to-Term Facility. Mesquite Wind Holding

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Record

Parties

Dates

Amounts