ARGAN INC (AGX)

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

This section of our 2025 Annual Report may include projections, assumptions and beliefs that are intended to be “forward-looking statements.” They should be read in light of our cautionary statement regarding “forward-looking statements” presented at the beginning of this 2025 Annual Report. The following discussion summarizes the financial position of Argan, Inc. and its subsidiaries as of January 31, 2025, and the results of their operations for Fiscal 2025 and Fiscal 2024, and should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in Item 8 of this 2025 Annual Report.

Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in the Company’s Annual Report on Form 10-K for the year ended January 31, 2024, that was filed with the SEC on April 11, 2024, for a discussion of financial trends, variance drivers and other significant matters for Fiscal 2024 as compared with Fiscal 2023.

Overview

The Company is primarily a construction firm that conducts operations through its wholly owned subsidiaries, GPS, APC, TRC and SMC across three distinct reportable business segments.

Power Industry Services: Through GPS and APC, we provide a full range of engineering, procurement, construction, commissioning, maintenance, project development and technical consulting services to the power generation market, including the renewable energy sector, for a wide range of customers, including independent power project owners, public utilities, power plant heavy equipment suppliers and other commercial firms with significant power requirements. Projects are located in the U.S., Ireland and the U.K.

Industrial Construction Services: Through TRC, we provide primarily field services that support new plant construction and additions, maintenance turnarounds, shutdowns and emergency mobilizations for industrial plants primarily located in the Southeast region of the U.S. and that may include the fabrication, delivery and installation of steel components such as piping systems and pressure vessels.

Telecommunications Infrastructure Services: Through SMC, which conducts business as SMC Infrastructure Solutions, we provide project management, construction, installation and maintenance services to commercial, local government and federal government customers primarily in the Mid-Atlantic region of the U.S.

Project Backlog

At January 31, 2025 and 2024, our consolidated project backlog amount of $1.4 billion and $0.8 billion, respectively, consisted substantially of projects within our power industry services reporting segment.

Our reported amount of project backlog at a point in time represents the total value of projects awarded to us that we consider to be firm as of that date less the amounts of revenues recognized to date on the corresponding projects. Typically, we include the total value of EPC services and other major construction contracts in project backlog upon receiving a notice to proceed from the project owner. When provided with an LNTP, we usually record only the value of the contract related to the LNTP initially. Nevertheless, the inclusion of contract values in project backlog may require management judgment based on the facts and circumstances. It is important to note that the start of new projects is primarily controlled by project owners and that delays may occur that are beyond our control.

We are committed to the construction of state-of-the-art, natural gas-fired power plants, as important elements of our country’s electricity-generation mix now and in the future. We target natural gas-fired power plant, renewable energy plant and industrial construction opportunities in the U.S., Ireland and the U.K. Our vision is to safely contribute to the construction of the energy infrastructure and state-of-the-art industrial facilities that are essential to future economic prosperity in the areas where we operate. We intend to realize this vision with motivated, creative, high-energy and customer-driven teams that are committed to delivering the best possible project results each and every time.

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Tarbert Next Generation Power Station

In January 2025, APC entered into an EPC services contract for an approximately 300 MW biofuel power plant located in County Kerry, Ireland. The Tarbert Next Generation Power Station will consist of Ansaldo Energia’s AE94.3A turbine that will run on 100% sustainable biofuels, specifically hydrotreated vegetable oil, with the potential to convert to hydrogen. The flexible power generated at the Tarbert Next Generation Power Station will help to support Ireland’s energy security while delivering a renewables-led system. Enabling works are now underway ahead of full construction commencing Fiscal 2026 with planned completion towards the end of calendar year 2027.

700 MW Combined-Cycle Project

In December 2024, GPS entered into an EPC services contract and received the corresponding FNTP with a customer for an approximately 700 MW combined-cycle natural gas-fired power plant located in the United States. Project activity commenced in the fourth quarter of Fiscal 2025.

405 MW Midwest Solar Project

In April 2024, GPS executed an LNTP with a customer to construct a utility-scale solar field in Illinois with the capacity to provide 405 MW of electrical power (the “405 MW Midwest Solar Project”). In August 2024, GPS received a full release for the activities on the EPC contract. The unique, multi-phased project includes solar-tracking panels that can be stowed by remote command for expected adverse weather events and will use pre-existing transmission and utility infrastructure from a nearby retired coal power plant. Project completion is scheduled for the first half of the fiscal year ending January 31, 2027 (“Fiscal 2027”).

Trumbull Energy Center

In October 2022, GPS added to project backlog the EPC services contract value of the Trumbull Energy Center, a 950 MW natural gas-fired power plant now under construction in Lordstown, Ohio (the “Trumbull Energy Center”). We received the FNTP from the project owner, Clean Energy Future-Trumbull, LLC, in November 2022. This combined cycle power station will consist of two Siemens Energy SGT6-8000H gas-fired, high efficiency, combustion turbines with two heat recovery steam generators and a single steam turbine. Project completion is scheduled for the first quarter of Fiscal 2027.

Midwest Solar and Battery Projects

In August 2023, GPS executed LNTPs for three solar and battery projects in Illinois (the “Midwest Solar and Battery Projects”). Under the LNTPs, GPS commenced early engineering and design activities as well as procurement of major equipment for construction of state-of-the-art solar energy and battery energy storage facilities. Between January and early May 2024, GPS received FNTPs on all three of the solar and battery projects. The three projects will cumulatively represent 160 MW of electrical power and 22 MW of energy storage. Two of these projects were completed in the fourth quarter of Fiscal 2025. Completion of the final project is expected in Fiscal 2026.

Louisiana LNG Facility

In June 2024, GPS entered into a subcontract and received FNTP for the installation of five 90 MW gas turbines for the dedicated supply of power to a liquified natural gas (“LNG”) facility in Louisiana. This project, led by GPS, is a collaboration with TRC and APC. Project completion is scheduled for the first half of Fiscal 2026.

Shannonbridge Power Project

APC entered into an EPC services contract with GE Vernova for the construction and commissioning of an open-cycle thermal power facility in County Offaly, Ireland, that has the capacity to generate approximately 264 MW of temporary emergency electrical power (the “Shannonbridge Power Project”). In August 2023, APC received the FNTP on this project. Substantial completion of this project, that is defined in the corresponding contract as system turnover for commissioning, occurred in March 2024, and as of January 31, 2025, no amounts related to this project remained in project backlog.

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ESB FlexGen Peaker Plants

In May 2022, APC entered into engineering and construction services contracts with the ESB to construct three 65 MW aero-derivative gas turbine flexible generation power plants in and around the city of Dublin, Ireland (“ESB FlexGen Peaker Plants”). Two of the power plants, the Poolbeg and Ringsend FlexGen Power Plants, are located on the Poolbeg Peninsula, and the Corduff FlexGen Power Plant is located in nearby Goddamendy. Substantial completion of each power facility occurred during the third quarter of Fiscal 2025, and as of January 31, 2024, no amounts related to these projects remained in project backlog.

TRC Project Backlog

As of January 31, 2025, TRC’s project backlog was approximately $53.2 million as compared to $127.5 million on January 31, 2024. For Fiscal 2025 and Fiscal 2024, TRC generated $167.6 million and $142.8 million in revenues, respectively. The increase in revenues for the current year from the comparative prior period highlights the results of our successful business development efforts in recent years with both new and recurring clients, particularly in securing larger industrial field service construction projects. Despite the decrease in the amount of TRC’s project backlog during the current year, we are encouraged by the number and size of opportunities in our project pipeline, and we expect the TRC project backlog will grow in Fiscal 2026.

Other Activity Subsequent to Year-end

In February 2025, an EPC services contract was awarded to GPS by Sandow Lakes Energy Company, LLC for a 1.2 GW ultra-efficient natural gas-fired power plant in Lee County, Texas. This project will be added to backlog upon receipt of a FNTP. Construction of this plant, which will be powered by two gas-fired turbines supplied by Siemens Energy, is scheduled to commence later this year and the project owner expects to commence power generation in 2028.

Contract Termination

In October 2021, APC UK was contracted to construct a 2 x 330 MW natural gas-fired power plant in Carrickfergus that is near Belfast, Northern Ireland, in an existing structure that was initially designed to enclose coal-fired power plant units. As previously disclosed, there were a number of challenges related to the Kilroot Project that adversely impacted our ability to execute as expected, including supply chain delays, material changes to the project, the COVID-19 omicron outbreak, the war in Ukraine and extreme weather. Unresolved variations and claims disrupted the execution and harmed the cash flow of this project.

APC UK provided 14 days’ notice to terminate as a result of project owner breaches of the contract. Those breaches were not resolved during that 14-day period, as a result of which the contract terminated on May 3, 2024. Subsequently, the project owner made a draw for the full amount of a $9.2 million irrevocable letter of credit, or on-demand performance bond, issued by the Company’s bank. This amount is now part of the open and disputed claims related to this project because APC UK and the Company believe the project owner initiated the draw without cause and, therefore, the amount should be refunded. This amount is included in accounts receivable as of January 31, 2025.

We have recognized an estimated contract loss related to the Kilroot Project in the amount of approximately $13.4 million, of which $3.4 million was recorded during Fiscal 2025 and the remainder was recorded in the prior fiscal year. APC UK has significant billable receivables, unresolved contract variations and claims for extensions of time, among other issues, related to the Kilroot Project. The project owner has asserted counterclaims that APC UK disputes. APC UK will continue to pursue all of its rights under the contract (see Note 10 to the accompanying consolidated financial statements).

Market Outlook

Growing Power Demand

Since 2007, total annual U.S. electricity demand has fluctuated, where eight of the years during that period experienced year-over-year decreases in energy consumption. However, U.S. electricity demand has since reached its highest level in two decades, reflecting a surge in consumption driven by emerging technologies and economic shifts. One prominent driver of this surge in energy demand is the rapid increase in the number of data centers, which are expanding to support the growing adoption of AI technologies. These facilities require substantial amounts of electricity to power advanced computing infrastructure, positioning them as a major contributor to future electricity demand. Technology companies

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with AI ambitions have begun exploring deals to bring more power to the grid in order to secure long-term power contracts to address their significant electricity demand. However, advancements in AI efficiency—as highlighted by DeepSeek, a generative AI model—could reduce the power required per computation, potentially moderating the overall anticipated surge in electricity demand. If these efficiency gains outpace current expectations, the anticipated expansion of data center power needs might be significantly lower than forecasted.

Other factors contributing to the projected growth of electricity demand in the U.S. are the accelerating shift toward electric vehicles (“EVs”) and the trend of onshoring manufacturing facilities. As more drivers transition to EVs, the need for electricity to power charging networks will grow significantly, further straining grid capacity. Meanwhile, companies relocating production to the U.S. to enhance supply chain resilience are increasing the energy requirements of industrial operations. Combined, these factors underscore a growing imperative for the U.S. energy sector to adapt to rising electricity demands in the coming decades.

Keeping up with growing energy demand is further challenged by the aging fleet of traditional power facilities that are at or nearing the end of their operational life. Throughout the U.S., the risk of electricity shortages grows as the retirement of traditional power plants outpaces their replacement. While renewable energy sources like solar and wind are expanding, they often cannot provide the same level of consistent, around-the-clock power generation as the retiring fossil-fuel plants. Electric-grid operators are warning that power-generating capacity is struggling to keep up with demand, a gap that could lead to additional rolling blackouts during heat waves or other peak power periods. As demand for electricity continues to surge—driven by factors such as an increase in data center development, industrial expansion, and the increasing electrification of transportation—these closures could place even greater strain on an already burdened grid, heightening reliability concerns across multiple regions.

Natural Gas Power

The overall growth of our power business has been substantially based on the number of combined cycle and simple cycle gas-fired power plants built by us, as many coal-fired plants have been shut down in the U.S. In 2010, coal-fired power plants accounted for about 45% of net electricity generation in the U.S. For 2024, coal fueled approximately 16% of net electricity generation. It has been reported that the average age of the active plants in the coal-fired fleet approximates 45 years old with an average life span of 50 years; the last coal-fired power plant built in the U.S. was constructed in 2015. On the other hand, natural-gas fired power plants provided approximately 42% of the electricity generated by utility-scale power plants in the U.S. in 2024, representing an increase of 70% in the amount of electrical power generated by natural gas-fired power plants since 2010. Natural gas-fired power plants provided approximately 24% of net electricity generation in 2010.

There exist certain headwinds confronting a significant resurgence in the pace of planning new developments of gas-fired power plants. Persistent supply chain constraints, which delay critical equipment delivery, and interconnect challenges that complicate grid integration delay project timelines and strain the availability of project financing. In addition, various cities, counties and states have adopted clean energy and carbon-free goals or objectives with achievement expected by a certain future date, typically 10 to 30 years out.

However, there appears to be a growing realization that such carbon-free goals present risks to the reliability of the electricity grids. For example, in November 2023, Texas voters approved the $10 billion Texas Energy Fund (“TEF”), thereby establishing a pool of funds intended to provide financing to projects that will enhance grid reliability and incentivize new dispatchable power generation projects, with a significant focus on natural gas-fired power plants. Shortly thereafter, the Public Utility Commission of Texas selected 17 natural gas-fired generation projects, totaling nearly 10 GW, to advance through a due diligence review, representing $5.4 billion in potential state-backed loans. Initial disbursements for the projects are expected to begin in late 2025, with construction on several sites already underway.

Solar, Wind, and Battery Power

The net amount of electricity generation in the U.S. provided by utility-scale solar photovoltaic and wind facilities continues to rise. Together, such power facilities provided approximately 16%, 15% and 13% of the net amount of electricity generated by utility-scale power facilities in 2024, 2023 and 2022, respectively. The EIA projected that new renewable power capacity will continue to be added to the utility-scale power fleet in the U.S. at a brisk pace, attributable to declines in costs of components for renewable power plants and power storage, an increase in the scale of energy storage capacity (i.e., battery farms and other energy storage technologies), and the availability of valuable tax credits.

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Battery storage has become a critical component in integrating renewable energy into the grid, addressing the intermittency of solar and wind power. In 2024, U.S. battery storage capacity nearly doubled, with developers adding 14.3 GW to the existing 15.5 GW. This rapid expansion enhances grid reliability and flexibility, allowing excess energy generated during peak production periods to be stored and used when demand is high or production is low. The integration of battery storage systems not only supports the stability of the power grid but also contributes to the economic viability of renewable energy projects.

Declining capital costs for solar panels, wind turbines and battery storage, as well as government subsidies like those included in the IRA, were projected to result in renewables becoming increasingly cost effective compared with the alternatives when the costs of building new power capacity were considered. The EIA indicated that for 2024, of the approximately 62.8 gigawatts of new utility-scale electric-generating capacity that was planned to be added to U.S. power grids, approximately 58% was expected to come from solar facilities, and 23% from battery storage.

Nuclear Power

Over the last several decades, the number of operating nuclear reactors has declined, with only four reactors entering commercial operation in the past 30 years—the most recent being Vogtle Units 3 and 4 in Georgia, which became operational in July 2023 and April 2024, respectively. These projects faced significant cost overruns—more than twice their initial estimates—and substantial delays, prompting the industry to shift its focus toward smaller, more economical designs such as small modular reactors. There is growing interest in expanding nuclear power production due to its minimal carbon footprint, but the limited industry activity over the past three decades has created challenges in ramping up development. As a result, it is widely expected that it could take up to a decade before the nuclear sector begins actively adding new plants to the power grid at scale.

The Regulatory Landscape

President Donald Trump's decision to withdraw the United States from the Paris Climate Agreement in January 2025 has significantly influenced the nation's energy production landscape. This move, coupled with a series of executive orders, has shifted federal policies to favor fossil fuel industries, impacting both renewable energy initiatives and the broader energy market. On his first day in office, President Trump declared a national energy emergency, aiming to boost domestic oil and gas production. This declaration has led to the suspension of certain environmental regulations, expedited approvals for fossil fuel projects, and the lifting of moratoriums on offshore drilling. The administration also established the National Energy Dominance Council to further streamline energy infrastructure projects and reduce regulatory barriers. These actions are intended to enhance energy independence and stimulate economic growth within traditional energy sectors. However, regulatory changes under the current administration are occurring at a rapid pace, which poses risks that the industry is unable to adapt in a timely manner.

In August 2022, President Biden signed the IRA, a bill that funds hundreds of billions of dollars in tax subsidies intended to combat climate change among other measures, with the receipt of the majority of the tax subsidies conditioned on the extent that taxpayers “buy American” and/or pay prevailing wages, among other requirements. Existing supply chains and skilled labor pools could lack the capacity to meet the demand that the incentives were intended to create. Therefore, the subsidies may not have provided the economic incentives to renewable and other energy project owners to the extent that was expected. Upon taking office in January 2025, President Trump initiated a 90-day review of aspects of the IRA and the Infrastructure Investment and Jobs Act. This action has paused disbursements of certain funds, including grants and loans, pending a review to ensure alignment with the new administration’s energy policies. This pause introduces additional uncertainty for ongoing and planned projects that rely on IRA incentives.

In May 2023, the Biden administration proposed new rules for the Environmental Protection Agency (the “EPA”) that were intended to drastically reduce greenhouse gases from coal- and gas-fired power plants that officials admit will cost such plants billions of dollars to comply fully by 2042. In April 2024, the EPA issued final rules that require coal-fired power plants that are expected to operate beyond 2039 to reduce their carbon emissions by 90% prior to 2032. For new gas-fired power plants, the rules require a sliding scale of carbon capture up to 90% based on the operational load of the individual power plant. Rules for existing natural gas power plants have been delayed until 2025 in response to concern that such rules could affect grid reliability. President Trump has expressed strong opposition to the EPA’s emissions-regulating rules and has pledged to abolish them.

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In June 2023, President Biden signed a bill that included reforms for certain elements of the permitting process for energy projects. Following the 2024 presidential election, President Trump has taken more significant steps to modify the permitting process. In January 2025, he signed executive orders prioritizing oil, gas, nuclear, coal, hydropower, biofuel, and critical mineral projects, while notably excluding wind and solar initiatives. These orders aim to expedite permitting for specific energy sectors by proposing changes to the National Environmental Policy Act (“NEPA”) to facilitate faster approvals.

In May 2024, the Biden administration launched the Federal-State Modern Grid Deployment Initiative, a collaborative measure between the federal government and twenty-one states intended to prioritize efforts that support the adoption of modern grid solutions to expand grid capacity and build modern grid capabilities for both new and existing transmission and distribution lines.

Changes in U.S. trade policy, particularly the introduction of higher and fluctuating tariffs, have created economic uncertainty, raising concerns in the construction sector about material price inflation and delivery delays. In January 2025, the U.S. announced new tariffs on imports from several nations, including Mexico, Canada, and China. Some of these tariffs were later postponed or modified. While intended to support broader policy objectives, these tariffs could disrupt supply chains, impact trade agreements, and increase costs while limiting access to materials essential for project execution. As trade negotiations continue and new policies are introduced, the tariff situation remains fluid, adding to the unpredictability of material costs and supply chain stability. The uncertainty surrounding trade policies may deter investment in new power plant or industrial construction projects, as stakeholders assess the financial viability amid fluctuating costs.

Behind-the-Meter Power Generation

The energy sector continues to experience significant shifts driven by evolving regulatory policies, technological advancements, evolving utility rate structures, and increasing customer demand for energy resilience and sustainability. A key trend influencing the market is the growing adoption of behind-the-meter (“BTM”) power generation assets, which allow commercial, industrial, and residential customers to generate electricity on-site rather than relying solely on the traditional grid. As BTM resources increase, grid operators may require more flexible and fast-ramping natural gas plants to balance intermittent generation from solar and other distributed energy resources, creating a role for gas-fired plants as reliability assets.

The adoption of BTM power generation is accelerating among commercial businesses, particularly data centers, seeking greater energy resilience, cost control, and sustainability. Most importantly, BTM power generation enables data centers and other commercial enterprises to connect to power more quickly, bypassing lengthy interconnection processes and delays associated with grid upgrades. Many companies are investing in on-site generation, such as solar-plus-storage and combined heat and power systems, to mitigate grid reliability risks, reduce peak demand charges, and meet corporate sustainability goals. While BTM generation offers businesses greater control over their energy use, it also challenges traditional utilities, requiring adjustments in grid management and revenue models.

Outlook for Natural Gas-Fired Power Plants

We believe that the lower operating costs of natural gas-fired power plants, the higher energy generating efficiencies of modern gas turbines, and the requirements for grid resiliency should sustain the demand for modern combined cycle and simple cycle gas-fired power plants in the future. We believe that the benefits of natural gas as a source of power are compelling, especially as a complement to the deployment of solar and wind-powered energy sources, and that the future long-term prospects for natural gas-fired power plant construction remain favorable as natural gas continues to be the primary source for power generation in our country. The future availability of less carbon-intense, higher efficiency and inexpensive natural gas in the U.S. should be a significant factor in the economic assessment of future power generation capacity additions, although the pace of new opportunities emerging may be restrained and the starts of awarded EPC projects may be delayed or canceled due to the challenges described above.

The current scramble for electricity, regardless of source, may indicate that the 100% transition to renewable energy is in the distant future and has prompted, in part, renewed interest in not only carbon capture techniques, but carbon removal technologies as well. Governments, including the U.S., are taking initial steps to boost this industry. The success of this industry could reduce the climate-change fear associated with natural gas-fired power plants. We intend to execute an “all-

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of-the-above” approach in pursuing the construction of future facilities that support the energy transition, which we see as a continuation of our historical commitment to building cleaner energy plants.

International Power Markets

The foregoing discussion in this “Market Outlook” has focused on the state of the domestic power market as the EPC services business of GPS historically provides the predominant portion of our revenues. However, overseas power markets may continue to provide important new power construction opportunities for APC, especially across Ireland and the U.K.

The Irish government has issued a policy statement on the security of the electricity supply in Ireland which confirms the requirement for the development of new support technologies to deliver on its commitment to have 80% of the country’s electricity generated from renewables by 2030. The report emphasizes that this will require a combination of conventional generation (typically powered by natural gas), interconnection to other jurisdictions, demand flexibility and other technologies such as battery storage and generation from renewable gases.

Whereas in the U.K., prior to the elections in July 2024, the government had expressed support for new gas-fired power plants to offset the retirement of coal-fired plants, the retirement of aging gas plants, and the intermittency of renewable energy plants. However, with the general election in July 2024, the Labour Party, led by Prime Minister Keir Starmer, has shifted focus toward accelerating the transition to renewable energy while still acknowledging the role of gas as a transitional fuel.

APC is actively pursuing business opportunities for natural gas-fired power generation projects with its existing and new clients. GPS has been providing top management guidance and project management expertise to APC. Currently, APC is undergoing a comprehensive operational review, in collaboration with GPS, to enhance project management processes.

Industrial Construction Services Outlook

Industrial field services typically represent the majority of TRC’s annual revenues with the remaining revenues contributed by projects consisting primarily of metal fabrication. Although TRC has worked on projects throughout the U.S., the primary business footprint for TRC encompasses the Southeast region of the U.S. where there are many local and state governments that welcome industrial production facilities with ideal locations and with serious economic development programs and incentives. The national focus on infrastructure improvements, biotechnology advancements, energy storage and clean water have resulted in firms that are focused on these trends recently choosing TRC to participate in major construction projects in the region. Other important factors and trends include low state corporate tax rates, favorable labor migration patterns, the surface transportation infrastructure and the ready access to modern seaports.

Economic data supports our belief that TRC is ideally located in a leading manufacturing growth area of the U.S., which should continue to provide it with project opportunities going forward that will expand its business and industrial construction capabilities. Despite headwinds such as rising labor costs and skilled labor shortages, it is likely that the near-term will see a boost to construction associated with manufacturing, as well as the transportation and clean energy infrastructures, as funds from three key pieces of national legislation passed in 2021 and 2022 are still expected to flow into the industry. These bills include the Infrastructure and Jobs Act, the IRA and the Creating Helpful Incentives to Produce Semiconductors Act, and they appear to be sustaining high construction industry confidence for the near future.

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Results of Operations

We reported net income of $85.5 million, or $6.15 per diluted share, for Fiscal 2025. For the prior fiscal year, we reported net income of $32.4 million, or $2.39 per diluted share.

The following schedule compares our operating results for Fiscal 2025 and Fiscal 2024 (dollars in thousands):

Revenues

Power Industry Services

The revenues of the power industry services business increased by 66.5%, or $276.8 million, to $693.0 million for Fiscal 2025 compared with revenues of $416.3 million for Fiscal 2024, as the current year construction activities increased for the Midwest Solar and Battery Projects, the Trumbull Energy Center, the 405 MW Midwest Solar Project and the Louisiana LNG Facility. The increase in revenues between years was partially offset by decreased construction activities associated with the Guernsey Power Station project, the ESB FlexGen Peaker Plants, the Shannonbridge Power Project and the Kilroot Project, as those projects have concluded. The revenues of this business represented approximately 79.3% of consolidated revenues for Fiscal 2025 and 72.6% of consolidated revenues for the prior year. The project backlog amounts for the power industry services reportable segment as of January 31, 2025 and 2024 were $1.3 billion and $0.6 billion, respectively.

Industrial Construction Services

The revenues of industrial construction services increased by $24.8 million, or 17.4%, to $167.6 million for Fiscal 2025 compared with revenues of $142.8 million for Fiscal 2024 as the amounts of field services construction activities increased meaningfully between periods, partially offset by decreased supporting vessel fabrication work between periods. The revenues of this business represented approximately 19.2% of consolidated revenues for Fiscal 2025 and 24.9% of consolidated revenues for the prior fiscal year.

Telecommunications Infrastructure Services

The revenues of telecommunications infrastructure services were $13.5 million for Fiscal 2025 compared with revenues of $14.3 million for Fiscal 2024.

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Cost of Revenues

Due primarily to the increase in consolidated revenues for Fiscal 2025 compared with revenues for Fiscal 2024, consolidated cost of revenues also increased. These costs were $733.2 million and $492.5 million for Fiscal 2025 and Fiscal 2024, respectively.

Gross Profit

For Fiscal 2025, we reported a consolidated gross profit of approximately $141.0 million, which represented a gross profit percentage of approximately 16.1% of corresponding consolidated revenues. For Fiscal 2024, we reported a consolidated gross profit of approximately $80.8 million, which represented a gross profit percentage of approximately 14.1% of corresponding consolidated revenues. The gross profit percentage increased between periods primarily due to the changing mix of projects and contract types. Additionally, during Fiscal 2025 and Fiscal 2024, gross profit was negatively impacted by losses recorded on the Kilroot Project, which reduced margins by approximately $3.4 million and $10.0 million, respectively. The gross profit percentages of corresponding revenues for the power industry services, industrial construction services and telecommunications infrastructure services segments for Fiscal 2025 were 16.7%, 13.3% and 23.8%, respectively.

The gross profit percentages of corresponding revenues for the power industry services, industrial construction services and telecommunications infrastructure services segments for Fiscal 2024 were 14.1%, 12.9% and 26.5%, respectively.

Selling, General and Administrative Expenses

Selling, general and administrative expenses were $52.8 million and $44.4 million for Fiscal 2025 and Fiscal 2024, respectively, representing 6.0% and 7.7% of consolidated revenues for the corresponding periods, respectively.

Other Income, Net

For Fiscal 2025 and Fiscal 2024, the net amounts of other income were $23.0 million and $12.5 million, respectively, which represented an increase of 84.4% between the comparable periods, as the weighted average balances of investments are meaningfully higher this year, and earnings related to cash and cash equivalent balances increased during Fiscal 2025 as well. Earnings on invested funds and interest-bearing cash accounts for Fiscal 2025 and Fiscal 2024 were $21.2 million and $14.1 million, respectively. Offsetting other income in the prior year was the wire-transfer fraud loss of $3.0 million that occurred in the first quarter of Fiscal 2024 (see Note 18 to the accompanying consolidated financial statements).

Income Tax Expense

We recorded income tax expense for Fiscal 2025 in the net amount of approximately $25.7 million primarily due to our reporting pre-tax income for financial reporting purposes in the amount of $111.2 million for the year. Our annual effective income tax rate for Fiscal 2025 was 23.2%. This tax rate differed from the statutory federal tax rate of 21% due to the unfavorable effect of state income taxes and the unfavorable effects of certain nondeductible expense amounts. Partially offsetting these unfavorable effects were the investment tax credit effect recorded in Fiscal 2025 related to our solar fund investments and the windfall benefit from stock-based compensation.

We recorded income tax expense for Fiscal 2024 in the net amount of approximately $16.6 million primarily due to our reporting pre-tax income for financial reporting purposes in the amount of $48.9 million for the year. Our annual effective income tax rate for Fiscal 2024 was 33.9%. This tax rate differed from the statutory federal tax rate of 21% due to the net operating loss of APC’s subsidiary in the U.K. that was not tax effected with benefit. Partially offsetting this unfavorable tax effect were the benefits provided by foreign tax rate differentials.

Liquidity and Capital Resources

At January 31, 2025 and 2024, our balances of cash and cash equivalents were $145.3 million and $197.0 million, respectively, which represented a decrease of $51.7 million between years.

The net amount of cash provided by operating activities for Fiscal 2025 was $167.6 million. Our net income for Fiscal 2025, adjusted favorably by the net amount of non-cash income and expense items, represented a source of cash in the total amount of $99.7 million. The temporary increase in contract liabilities of $118.2 million represented a source of cash, primarily due to the net effect of the early phase of construction activities on certain projects. The increase in the combined

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level of accounts payable and accrued expenses in the amount of $66.2 million represented a meaningful source of cash during the period as well. The decrease in contract assets of $19.8 million represented a source of cash, primarily due to the completion of projects during the period. The increase of accounts receivable in the amount of $128.6 million, which represented a use of cash during the period, was due primarily to the increase in revenues during the period and timing of billings, but also related to the Kilroot Project. The increase in other assets of $7.7 million represented a use of cash during the period.

During Fiscal 2025, we used $120.7 million, net of maturities, to invest in available-for-sale (“AFS”) securities consisting primarily of U.S. Treasury notes. We also used $45.0 million, net of maturities, to invest in CDs issued by the Bank. We used $16.3 million to invest in a new solar tax credit entity and fund our remaining capital contribution obligation to a solar energy project we invested in during the prior year. We also used $6.6 million for the purchases of property, plant and equipment.

For Fiscal 2025, we used $26.1 million cash in financing activities, including $18.3 million used for the payment of regular cash dividends and $1.5 million used to repurchase shares of common stock pursuant to our share repurchase program. We also used $6.3 million for share-based award settlements, which represented the net of payments of $12.7 million for withholding taxes reimbursed by shares of common stock and $6.5 million of proceeds from the exercise of stock options during the period. As of January 31, 2025, there were no restrictions with respect to intercompany payments between the holding company, GPS, TRC, APC and SMC.

At January 31, 2025, a portion of our balance of cash and cash equivalents was invested in a money market fund with most of its net assets invested in cash, U.S. Treasury obligations, other obligations issued by U.S. Government agencies and sponsored enterprises, and repurchase agreements secured by U.S. government obligations. The major portion of our domestic operating bank account balances are maintained with the Bank. We do maintain certain Euro-based bank accounts in Ireland and certain pound sterling-based bank accounts in the U.K. in support of the operations of APC.

In order to monitor the actual and necessary levels of liquidity for our business, we focus on working capital, or net liquidity, in addition to our cash balances. Our net liquidity increased by $56.5 million to $301.4 million as of January 31, 2025 from $244.9 million as of January 31, 2024, due primarily to our net income for the fiscal year, partially offset by the payment of cash dividends, common stock repurchases, and net cash paid for withholding taxes due to stock-based award net settlements. As we have no debt service, as our fixed asset acquisitions in a reporting period are typically low, and as our net liquidity includes our short-term investments and AFS investments, our levels of working capital are not subjected to the volatility that affects our levels of cash and cash equivalents.

We believe that cash on hand, our cash equivalents, cash that will be provided from the maturities of short-term investments and other debt securities and cash generated from our future operations, with or without funds available under our New Credit Agreement, will be adequate to meet our general business needs in the foreseeable future. In general, we maintain significant liquid capital in our consolidated balance sheet to ensure the maintenance of our bonding capacity and to provide parent company performance guarantees for EPC and other construction projects.

However, any significant future acquisition, investment or other unplanned cost or cash requirement, may require us to raise additional funds through the issuance of debt and/or equity securities. There can be no assurance that such financing will be available on terms acceptable to us, or at all.

Financing Arrangements

On May 24, 2024, we executed with the Bank the New Credit Agreement with an expiration date of May 31, 2027. The New Credit Agreement supersedes the Expired Credit Agreement, reduces the base lending commitment amount from $50.0 million to $35.0 million, increases the letter of credit fees to be consistent with current market conditions, and establishes the interest rate for revolving loans at SOFR plus 1.85%. In addition to the base commitment, the new facility includes an accordion feature that allows for an additional commitment amount of $30.0 million, subject to certain conditions. We may use the borrowing ability to cover other credit instruments issued by the Bank for our use in the ordinary course of business as defined in the New Credit Agreement. Further, on May 31, 2024, we entered into a companion facility, in the amount of $25.0 million, pursuant to which the Company’s Irish subsidiary, APC, may cause the Bank’s European entity to issue letters of credit on its behalf that are secured by a blanket parent company guarantee issued by Argan to the Bank. Despite the reduction in the base amount of the credit commitment provided by the New

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Credit Agreement, the increased accordion amount and the addition of the companion facility provide us with greater flexibility in managing our credit requirements, at a potentially lower cost.

At January 31, 2025 and 2024, we did not have any borrowings outstanding under the New Credit Agreement or the Expired Credit Agreement, respectively. At January 31, 2025, there were no outstanding letters of credit issued under the credit facilities.

We have pledged the majority of the Company’s assets to secure its financing arrangements. The Bank’s consent is not required for acquisitions, divestitures, cash dividends or significant investments as long as certain conditions are met. The New Credit Agreement requires that the we comply with certain financial covenants at its fiscal year-end and at each fiscal quarter-end. The New Credit Agreement includes other terms, covenants and events of default that are customary for a credit facility of its size and nature, including a requirement to achieve positive adjusted earnings before interest, taxes, depreciation and amortization, as defined, over each rolling twelve-month measurement period. As of January 31, 2025, we were in compliance with the covenants and other requirements of the New Credit Agreement.

Contractual Obligations

During Fiscal 2025, there was no significant change in the nature or amounts of our contractual obligations. We estimate that the balance of such contractual obligations as of January 31, 2025 was less than $20.0 million. The two largest items in this estimate, operating leases and deferred compensation, are amounts included as liabilities in our consolidated balance sheet. The remainder of such obligations relate primarily to open service arrangements. Outstanding commitments represented by open purchase orders and subcontracts related to our construction contracts have not been included in the estimated amounts of contractual obligations as such amounts are expected to be funded through contract billings to customers. We do not have any significant obligations for materials or subcontracted services beyond those required to complete construction contracts awarded to us.

Performance Bonds and Guarantees

In the normal course of business and for certain major projects, we may be required to obtain surety or performance bonding, to provide parent company guarantees, or to cause the issuance of letters of credit (or some combination thereof) in order to provide performance assurances to clients on behalf of one of our subsidiaries.

If our services under a guaranteed project would not be completed or would be determined to have resulted in a material defect or other material deficiency, then we could be responsible for monetary damages or other legal remedies. As is typically required by any surety bond, we would be obligated to reimburse the issuer of any surety bond provided on behalf of a subsidiary for any cash payments made thereunder. The commitments under performance bonds generally end concurrently with the expiration of the related contractual obligation. Not all of our projects require bonding.

As of January 31, 2025, the estimated amount of our unsatisfied bonded performance obligations, covering all of our subsidiaries, was approximately $0.7 billion. In addition, as of January 31, 2025, the outstanding amount of bonds covering other risks, including warranty obligations and contract payment retentions related to completed activities, was $25.2 million.

When sufficient information about claims related to performance on projects would be available and monetary damages or other costs or losses would be determined to be probable, we would record such losses. As our subsidiaries are wholly owned, any actual liability related to contract performance is ordinarily reflected in the financial statement account balances determined pursuant to the Company’s accounting for contracts with customers. Any amounts that we may be required to pay in excess of the estimated costs to complete contracts in progress as of January 31, 2025 are not estimable.

Solar Energy Project Investments

We make investments in limited liability companies that make equity investments in solar energy projects that are eligible to receive energy tax credits, for which we have received substantially all of the income tax benefits associated with those investments. During Fiscal 2024, we made an investment of approximately $5.1 million cash in a solar tax credit entity, and during the first quarter of Fiscal 2025, we paid $3.3 million in cash to satisfy our remaining capital contribution obligation.

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Later in Fiscal 2025, we evaluated and entered into an investment opportunity in an additional solar tax credit entity, where we contributed $13.0 million in the fourth quarter of Fiscal 2025. As of January 31, 2025, we have $11.5 million remaining of cash investment commitments related to this solar fund, which we expect to fulfill in Fiscal 2026. It is likely that we will evaluate opportunities to make other solar energy investments of this type in the future.

Development Financing

We selectively participate in power plant project development and related financing activities 1) to maintain a proprietary pipeline for future EPC services contract opportunities, 2) to secure exclusive rights to EPC contracts, and 3) to generate profits through interest income and project development success fees. As is common in our industry, EPC contractors and third parties periodically form joint ventures, limited partnerships and limited liability companies for purposes of executing a project or program for a project owner. These teaming arrangements are typically dissolved upon completion of the project or program. In addition, we may obtain interests in VIEs formed by its owners for a specific purpose. The evaluation of whether such interests represent our financial control of a VIE requires analysis and judgment.

In Fiscal 2023, we deconsolidated a VIE that had been formed for the purpose of developing a natural gas-fired power plant in Virginia (see Note 15 to the accompanying consolidated financial statements). GPS had provided development financing to this special purpose entity pursuant to a promissory note. However, the project owner was unable to obtain the necessary equity financing for the project, and the special purpose entity dissolved.

We have entered into similar support arrangements with other independent parties in the past that resulted in the successful development and our construction of three separate gas-fired power plant projects. We were paid project development fees for each project and our loans to the development entities were repaid in full plus interest. In each of these cases, we deconsolidated the corresponding VIE when we were no longer the primary beneficiary.

In Fiscal 2025, we funded a loan to a special purpose entity in the amount of $5.0 million to support the development phase of a natural gas-fired power plant (see Note 18 to the accompanying consolidated financial statements). We may enter into other support arrangements in the future in connection with power plant development opportunities when they arise and when we are confident that providing early financial support for the projects will lead to the award of the corresponding EPC contracts to us.

Earnings before Interest, Taxes, Depreciation and Amortization (“EBITDA”)

We believe that EBITDA is a meaningful presentation that enables us to assess and compare our operating performance on a consistent basis by removing from our operating results the impacts of our capital structure, the effects of the accounting methods used to compute depreciation and amortization and the effects of operating in different income tax jurisdictions. Further, we believe that EBITDA is widely used by investors and analysts as a measure of performance.

However, as EBITDA is not a measure of performance calculated in accordance with U.S. GAAP, we do not believe that this measure should be considered in isolation from, or as a substitute for, the results of our operations presented in accordance with U.S. GAAP that are included in our consolidated financial statements. In addition, our EBITDA does not necessarily represent funds available for discretionary use and is not necessarily a measure of our ability to fund our cash needs.

The following table presents the determinations of EBITDA for Fiscal 2025 and Fiscal 2024, respectively (amounts in thousands).

Deferred Tax Assets and Liabilities

Our consolidated balance sheet as of January 31, 2025 includes net deferred tax assets in the amount of approximately $0.6 million. The components of our deferred taxes are presented in Note 12 to the accompanying consolidated financial

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statements. These amounts reflect differences in the periods in which certain transactions are recognized for financial and income tax reporting purposes.

We consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized on a jurisdiction-by-jurisdiction basis. Our ability to realize our deferred tax assets depends primarily upon the generation of sufficient future taxable income to allow for the realization of our deductible temporary differences. If such estimates and assumptions regarding income amounts change in the future, we may be required to record additional valuation allowances against some or all of the deferred tax assets resulting in additional income tax expense in our consolidated statement of earnings.

During Fiscal 2020, a valuation allowance in the amount of $7.1 million was established against the deferred tax asset amount created by the NOL of APC UK. During Fiscal 2023, APC UK continued a turnaround of its operating results such that we believed it had a stable earnings history upon which APC UK could reliably forecast future profitable operations. Accordingly, we reversed a portion of the corresponding allowance during Fiscal 2023 in the amount of $2.6 million. However, the unexpected difficulties with one construction project and the loss that was recorded by APC UK related to it caused management to increase the amount of the allowance by $2.1 million in Fiscal 2024. During Fiscal 2025, the valuation allowance was increased by $1.4 million related to additional operating losses incurred by APC UK during the fiscal year. As of January 31, 2025, the potential income tax benefits associated with the NOLs of APC UK are fully offset by a valuation allowance.

A deferred tax asset in the amount of $8.3 million was recorded as of January 31, 2020 associated with the income tax benefit of our domestic NOL for Fiscal 2020 without any corresponding valuation allowance. Among other changes, the CARES Act re-established a carryback period for certain losses to five years. The NOLs eligible for carryback under the CARES Act include our domestic loss for Fiscal 2020, which was approximately $39.5 million. The carryback provided a favorable rate benefit for us as the loss, which was incurred in a year where the statutory federal tax rate was 21%, has been carried back to tax years where the tax rate was higher. The net amount of this additional income tax benefit, which we recorded in Fiscal 2021, was $4.4 million. We have made the appropriate filings with the IRS requesting carryback refunds of income taxes paid in prior years. With the enactment of the CARES Act, the asset amount, which totals $12.7 million, was moved to income taxes receivable. The IRS has not completed the examination of our refund request.

At this time, we believe that the historically strong earnings performance of our power industry services segment will provide sufficient income during the years when most of our other deferred tax assets become deductible in the U.S. in order for us to realize the applicable temporary income tax differences. Accordingly, we believe that it is more likely than not that we will realize the benefit of significantly all of our net deferred tax assets.

Critical Accounting Policies

Critical accounting policies are those related to the areas where we have made what we consider to be particularly subjective or complex judgments in arriving at estimates and where these estimates can significantly impact our financial results under different assumptions and conditions.

These estimates, judgments, and assumptions affect the reported amounts of assets, liabilities and equity, the disclosure of contingent assets and liabilities at the dates of financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets, liabilities and equity that are not readily apparent from other sources. Actual results and outcomes could differ from these estimates and assumptions. We do periodically review these critical accounting policies and estimates with the audit committee of our board of directors.

We consider the accounting policies related to revenue recognition on long-term construction contracts to be most critical to the understanding of our financial position and results of operations.

Revenue Recognition

Our revenues are primarily derived from construction contracts that can span several quarters or years. We enter into EPC and other long-term construction contracts principally on the basis of competitive bids or in conjunction with our support of the development of power plant projects. The types of contracts may vary. However, the EPC contracts of our power

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industry services reporting segment, and most other large contracts awarded to our other companies, are fixed-price contracts. Revenues are recognized primarily over time as performance obligations are satisfied due to the continuous transfer of control to the project owner or other customer. The accuracy of our revenues and profit recognition in a given period depends on the accuracy of our estimates of the forecasted contract value, or transaction price, and the cost to complete the work for each project.

Central to accounting for revenues from contracts with customers is a five-step revenue recognition model that requires reporting entities to:

The guidance focuses on the transfer of the control of the goods and/or services to the customer, as opposed to the transfer of risk and rewards. Major provisions cover the determination of which goods and services are distinct and represent separate performance obligations, the appropriate treatment of variable consideration, and the evaluation of whether revenues should be recognized at a point in time or over time. In general, application of the rules requires us to make important judgments and meaningful estimates that may have significant impact on the amounts of revenues recognized by us for any reporting period.

Revenues from fixed-price contracts, including portions of estimated gross profit, are recognized as services are provided, based on costs incurred and estimated total contract costs using the cost-to-cost approach. The cost and profit estimates are re-forecasted monthly for all significant contracts pursuant to a detailed determination and review process. The results of the process are subjected to reviews by senior management with the applicable project management personnel at each subsidiary. The depth of the reviews may vary between projects depending on the percentage-of-completion for the projects, among other factors. The cost-to-cost method measures the ratio of costs incurred and accrued to date for each contract to the estimated, or forecasted, total cost for each contract at completion. This requires us to prepare on-going estimates of the forecasted cost to complete each contract as the project progresses. In preparing these estimates, we make significant judgments and assumptions about our significant costs, including materials, labor and equipment, and we evaluate contingencies based on possible schedule variances, major equipment delivery delays, construction delays, weather or other productivity factors.

Actual costs may vary from the costs we estimate. Variations from estimated contract costs, along with other risks inherent in fixed-price contracts, may result in actual revenues and gross profits differing from those we estimate and could result in losses on projects or other significant unfavorable impacts on our operating results for any fiscal quarter or year. If a current estimate of total contract cost indicates a loss on a contract, the projected loss is recognized in full when determined, without regard to the percentage of completion. There are a number of factors that can contribute to changes in estimated contract costs, revenues and profitability. The most significant of these are identified in the first item included in the Risks Related to our Operational Execution section of Part I, Item 1A. of this Annual Report entitled Risk Factors.

Crucial to the compliance with the accounting standard covering the recognition of revenues on contracts with customers is the identification of the promises made to the customer by us that are included in the contract. If a promise is distinct, as that concept is defined in the accounting standard, it represents a separate performance obligation. Contracts may have multiple promises. The amounts of revenue associated with each promise are recognized when, or as, the performance obligations are satisfied. However, complex contracts may include only one performance obligation if the multiple promises are not distinct within the context of the contract. For example, if the promises that could be considered distinct are interrelated or require us to perform integration so that the customer receives a complete product, the contract is considered to include only one performance obligation. Most of our long-term contracts have a single performance obligation as the promises to transfer individual goods or services are not separately identifiable from other promises within the context of the contract. Our EPC contracts require us to deliver a complete and functioning power plant, not just functioning components.

The transaction price of a contract represents the value used to determine the amount of revenues recognized as of the balance sheet date. It may reflect amounts of variable consideration, which could be either increases or decreases to the

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transaction price. These adjustments can be made from time-to-time during the period of contract performance as circumstances evolve related to such items as variations in the scope and price of contracts, claims, incentives and liquidated damages.

We may include an estimated amount of variable consideration in the transaction price to the extent it is probable that a significant reversal of cumulative revenues recognized on the particular contract will not occur when the uncertainty associated with the variable consideration is resolved. The Company’s determination of the amount of variable consideration to be included in the transaction price of a particular contract is based largely on an assessment of the Company’s anticipated performance and all information (historical, current and forecasted) that is reasonably available. The effect of any revisions to the transaction price on the amount of previously recognized revenues that is due to the addition or reduction of variable consideration is recorded currently as an adjustment to revenues on a cumulative catch-up basis. In the event that any amounts of variable consideration that are reflected in the transaction price of a contract are not resolved in the Company’s favor, there could be reductions in, or reversals of, previously recognized revenues. In most significant instances, modifications to our contracts do not represent the addition of new performance obligations.

Contract results may be impacted by estimates of the amounts of contract variations that we expect to receive. The effects of any resulting revisions to revenues and estimated costs can be determined at any time and they could be material. As of January 31, 2025 and 2024, the aggregate amounts of contract variations reflected in estimated transaction prices that were pending customer approval were $8.0 million and $8.4 million, respectively.

Substantially all of our customer contracts include the right for customers to terminate contracts for convenience as disclosed in Note 2 to the consolidated financial statements. The value of future work that companies are contractually obligated to perform pursuant to active customer contracts should not be included in the disclosure of remaining unsatisfied performance obligations (“RUPO”) when the corresponding contracts include termination for convenience clauses without substantial penalties accruing to the customers upon such terminations. In the application of this guidance, we assess whether the nature of the work being performed under contract is largely service-based and repetitive and should be considered a succession of one-month contracts for the duration of the identified term of the contract. Predominantly, our customers contract with us to construct assets, to fabricate materials or to perform emergency maintenance or outage services where we believe a substantial penalty or cost would be incurred upon a termination for convenience. We believe that in substantially all cases, there would be substantial costs incurred by a customer if it terminated a contract with us for convenience including the costs of terminating subcontracts, canceling purchase orders, returning or otherwise disposing of delivered materials and equipment and restarting the effort with another contractor. Further, to the best of management’s knowledge, the Company has never had a customer terminate a material contract with us for convenience. Therefore, our disclosure in Note 2 of the value of RUPO on active customer contracts represents an amount based on contracts or orders received from customers that the Company believes are firm and where the parties are acting in accordance with their respective obligations.

Our long-term contracts typically have schedule dates and other performance obligations that, if not achieved, could subject us to liquidated damages. These contract requirements generally relate to specified activities that must be completed by an established date or by achievement of a specified level of output or efficiency. Each contract defines the conditions under which a project owner may make a claim for liquidated damages. The amounts of liquidated damages owed to a project owner pursuant to the terms of a contract would represent reductions of the transaction price of the corresponding contract.

At the outset of each of the Company’s contracts, the potential amounts of liquidated damages typically are not subtracted, from the transaction price as the Company believes that it has included activities in its contract plan, and has reflected the associated costs in its forecasts of completed contract costs, that will be effective in preventing such damages. Of course, circumstances may change as the Company executes the corresponding contract. The transaction price is reduced by an applicable amount when the Company no longer considers it probable that a future reversal of revenues will not occur when the matter is resolved. In general, we consider potential liquidated damages, the costs of other related items and potential mitigating factors in determining the estimates of forecasted revenues and the adequacy of our estimates of the cost to complete contracts.

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Recently Issued Accounting Pronouncements

See Note 1 to the accompanying consolidated financial statement for discussion of recently issued accounting pronouncements.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

This section of our 2024 Annual Report may include projections, assumptions and beliefs that are intended to be “forward-looking statements.” They should be read in light of our cautionary statement regarding “forward-looking statements” presented at the beginning of this 2024 Annual Report. The following discussion summarizes the financial position of Argan, Inc. and its subsidiaries as of January 31, 2024, and the results of their operations for Fiscal 2024 and Fiscal 2023, and should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in Item 8 of this 2024 Annual Report.

Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in the Company’s Annual Report on Form 10-K for the year ended January 31, 2023, that was filed with the SEC on April 17, 2023, for a discussion of financial trends, variance drivers and other significant matters for Fiscal 2023 as compared with Fiscal 2022.

Business Description

The Company is primarily a construction firm that conducts operations through its wholly-owned subsidiaries, GPS, APC, TRC and SMC. Through GPS and APC we provide a full range of engineering, procurement, construction, commissioning, maintenance, project development and technical consulting services to the power generation market, including the renewable energy sector, for a wide range of customers, including independent power project owners, public utilities, power plant heavy equipment suppliers and other commercial firms with significant power requirements in the U.S., Ireland and the U.K. GPS and APC represent our power industry services reportable segment. Through TRC, the industrial construction services reportable segment provides primarily field services that support new plant construction and additions, maintenance turnarounds, shutdowns and emergency mobilizations for industrial plants primarily located in the Southeast region of the U.S. and that may include the fabrication, delivery and installation of steel components such as piping systems and pressure vessels. Through SMC, which conducts business as SMC Infrastructure Solutions, the telecommunications infrastructure services segment provides project management, construction, installation and maintenance services to commercial, local government and federal government customers primarily in the Mid-Atlantic region of the U.S.

We may make additional opportunistic acquisitions and/or investments by identifying companies with significant potential for profitable growth and realizable synergies with one or more of our existing businesses. However, we may have more than one industrial focus depending on the opportunity and/or needs of our customers. Significant acquired companies will be operated in a manner that we believe will best provide long-term and enduring value for our stockholders.

Overview

Operating Results

Consolidated revenues for Fiscal 2024 were $573.3 million, which represented an increase of $118.3 million, or 26.0%, from consolidated revenues of $455.0 million reported for Fiscal 2023.

The revenues of the power industry services segment increased by $70.3 million to $416.3 million for Fiscal 2024 from $346.0 million reported for Fiscal 2023, representing an increase of 20.3%. The revenues of this reportable segment represented 72.6% of consolidated revenues for Fiscal 2024. For Fiscal 2023, the percentage share of consolidated revenues represented by this reportable segment was 76.0%. The industrial construction services business reported revenues of $142.8 million for Fiscal 2024. This amount represented an increase of $50.0 million, or 53.9%, from revenues of $92.8 million reported for Fiscal 2023. Revenues provided by this reportable business segment represented 24.9% and 20.4% of corresponding consolidated revenues for Fiscal 2024 and Fiscal 2023, respectively. Revenues of the telecommunications infrastructure services business decreased to $14.3 million for Fiscal 2024 from revenues of $16.2 million for Fiscal 2023. Revenues provided by this reportable segment represented 2.5% and 3.6% of corresponding consolidated revenues for Fiscal 2024 and Fiscal 2023, respectively.

Consolidated gross profit declined by $5.5 million, or 6.4%, to $80.8 million for Fiscal 2024, or 14.1% of the corresponding consolidated revenues. The amount of consolidated gross profit reported for Fiscal 2023 was $86.4 million, or 19.0% of

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the corresponding consolidated revenues. The reduction in the overall gross profit amount and percentage for the current fiscal year was primarily due to the recorded loss of $13.6 million related to APC’s construction contract in Northern Ireland. The effect of the contract loss on the gross profit amount for Fiscal 2024 was meaningfully offset by the profits earned on the performance of other projects by each of our four operating companies, including APC.

Selling, general and administrative expenses for Fiscal 2024 and Fiscal 2023 were $44.4 million, or 7.7% of corresponding consolidated revenues, and $44.7 million, or 9.8% of corresponding consolidated revenues, respectively. The net amount of other income increased significantly for Fiscal 2024 to $12.5 million from $4.3 million reported for Fiscal 2023 due primarily to increased investment income.

Due primarily to the consolidated pre-tax book income reported for Fiscal 2024 in the amount of $48.9 million, we reported income tax expense in the amount of $16.6 million for the year. For Fiscal 2023, we reported consolidated pre-tax book income of $46.0 million and recorded income tax expense in the amount of $11.3 million.

For Fiscal 2024, our overall operating performance resulted in net income attributable to our stockholders in the amount of $32.4 million, or $2.39 per diluted share. For Fiscal 2023, our overall operating performance resulted in net income attributable to our stockholders in the amount of $33.1 million, or $2.33 per diluted share.

Project Backlog

At January 31, 2024 and 2023, our consolidated project backlog amount of $0.8 billion consisted substantially of the projects of the power industry services reporting segment. Our reported amount of project backlog at a point in time represents the total value of projects awarded to us that we consider to be firm as of that date less the amounts of revenues recognized to date on the corresponding projects.

Typically, we include the total value of EPC services and other major construction contracts in project backlog upon receiving a notice to proceed from the project owner. When provided with LNTP, we usually record only the value of the contract related to the LNTP initially. Nevertheless, the inclusion of contract values in project backlog may require management judgement based on the facts and circumstances.

We are committed to the construction of state-of-the-art, natural gas-fired power plants, as important elements of our country’s electricity-generation mix now and in the future. This represents our core business. In addition, we have been directing meaningful business development efforts to winning projects for the erection of utility-scale solar fields and wind farms and for the construction of hydrogen-based energy and other industrial projects in order to diversify the sources of revenues. We have successfully completed alternative energy projects in the past and we have renewed efforts to obtain new work in other sectors of the power market that will complement our natural gas-fired EPC services projects going forward.

It is important to note that the start of new projects is primarily controlled by project owners and that delays may occur that are beyond our control. However, we continue to pursue natural gas-fired power plant, renewable energy plant and industrial construction opportunities in the U.S., Ireland and the U.K. Our vision is to safely contribute to the construction of the energy infrastructure and state-of-the-art industrial facilities that are essential to future economic prosperity in the areas where we operate. We intend to realize this vision with motivated, creative, high-energy and customer-driven teams that are committed to delivering the best possible project results each and every time.

Trumbull Energy Center

In October 2022, GPS added to project backlog the EPC services contract value of the Trumbull Energy Center, a 950 MW natural gas-fired power plant now under construction in Lordstown, Ohio (the “Trumbull Energy Center”). We received the full notice to proceed from the project owner, Clean Energy Future-Trumbull, LLC, in November 2022. This combined cycle power station will consist of two Siemens Energy SGT6-8000H gas-fired, high efficiency, combustion turbines with two heat recovery steam generators and a single steam turbine. Project completion is scheduled for early in the year ending January 31, 2027.

Guernsey Power Station

In January 2019, GPS entered into an EPC services contract to construct an 1,875 MW natural gas-fired power plant in Guernsey County, Ohio (the “Guernsey Power Station”). Caithness Energy, L.L.C. (“Caithness”) led the development of

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this project. Using state-of-the-art combined cycle technology and an air-cooling system, the Guernsey Power Station will be a cost-efficient, fuel-efficient, electricity generating power plant that protects air quality and conserves water with the capability to satisfy the electricity needs of approximately one million homes.

The combined cycle design of this plant utilizes three power trains, with each one including a gas-fired turbine, a heat recovery steam generator and a steam turbine, that will enable this plant to generate significantly more power from the equivalent amount of fuel than a traditional gas-fired power plant. The Guernsey Power Station also uses dry cooling technology to reduce water usage by as much as 95% compared with a water-cooled power plant. Because of its advanced design, the power plant will achieve extremely low emission levels from a gas-fired power plant of its type.

After receiving a full notice-to-proceed, GPS commenced substantial activities for this project in August 2019, which remains the largest, single-phase, gas-fired, power plant construction project in the U.S. Completion of construction activities on this project occurred during Fiscal 2024, and as of January 31, 2024, a nominal amount related to this effort remains in project backlog.

It should be noted that this major project, the largest in the history of GPS, was substantially executed during the worst phases of the COVID-19 epidemic and the most severe global impacts of the recent overall supply chain disruptions. Yet, the completed plant was delivered successfully to the project owner.

Midwest Solar and Battery Projects

In August 2023, GPS executed LNTPs with a customer for three solar and battery projects in Illinois (the “Midwest Solar and Battery Projects”). Under the LNTPs, GPS commenced early engineering and design activities as well as procurement of major equipment for construction of state-of-the-art solar energy and battery energy storage facilities. In January 2024, GPS received full notices to proceed on two of the solar and battery projects. The three projects will cumulatively represent 160 MW of electrical power and 22 MW of energy storage.

Maple Hill Solar Facility

In May 2021, we announced that GPS entered into an EPC services contract with CPV Maple Hill Solar, LLC, an affiliate of Competitive Power Ventures, Inc. (“CPV”), to construct the Maple Hill Solar facility, which is among the largest solar-powered energy plants in Pennsylvania. The unique Maple Hill Solar project, which is located in Cambria County, includes over 235,000 photovoltaic modules for the generation of up to approximately 100 MW of electrical power. Final completion of the project and site demobilization occurred near the end of Fiscal 2024, and as of January 31, 2024, no amount related to Maple Hill remained in project backlog.

Shannonbridge Power Project

APC entered into an EPC services contract with GE Vernova for the construction and commissioning of an open-cycle thermal power facility in County Offaly, Ireland, that will have the capacity to generate approximately 264 MW of temporary emergency electrical power (the “Shannonbridge Power Project”). The Shannonbridge Power Project, an initiative of EirGrid and the Electricity Supply Board of Ireland (the “ESB”), aims to enhance the region’s power infrastructure and to ensure a reliable electricity supply during critical situations and emergencies. GPS is teaming with APC in performance of this contract. Work on this project commenced early in Fiscal 2024 pursuant to the receipt of a series of LNTPs. In August 2023, APC received the full notice to proceed on this project. Project completion is expected in the first half of the fiscal year ending January 31, 2025 (“Fiscal 2025”).

ESB FlexGen Peaker Plants

In May 2022, APC entered into engineering and construction services contracts with the ESB to construct three 65 MW aero-derivative gas turbine flexible generation power plants in and around the city of Dublin, Ireland (“ESB FlexGen Peaker Plants”). Two of the power plants, the Poolbeg and Ringsend FlexGen Power Plants, are located on the Poolbeg Peninsula, and the Corduff FlexGen Power Plant is located in nearby Goddamendy. All three projects cleared the applicable capacity auction in Fiscal 2023 and are expected to operate intermittently during peak periods of electricity demand and as back-up supply options when renewable electricity generation is limited. The completion of each power facility is expected to occur in early Fiscal 2025.

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Kilroot Power Station

In October 2021, APC was contracted to construct a 2 x 330 MW natural gas-fired power plant in Carrickfergus that is near Belfast, Northern Ireland, in an existing structure that was initially designed to enclose coal-fired units (the “Kilroot Power Station” or the “Kilroot” project). See “The Kilroot Project Loss” below for discussion of the challenges related to this project and the loss recorded in Fiscal 2024 related to this project.

TRC Project Backlog

As of January 31, 2024, TRC’s project backlog was approximately $127.5 million, slightly up from $123.5 million on January 31, 2023, demonstrating the ability to maintain and increase project backlog despite converting a significant amount of previous project backlog into revenues, which increased by approximately 53.9% in Fiscal 2024 as compared to Fiscal 2023. This consistency is a result of targeted efforts to win larger industrial field service construction projects from both new and recurring clients. Following this strategic direction, TRC has streamlined by consolidating its pipe and vessel fabrication facilities, aiming to lower fixed costs and enhance operations for a scalable business model amidst growing construction demands.

Project Backlog Subsequent to Year-end

Since January 31, 2024, we have added to our project backlog as a result of GPS and TRC entering into several contract agreements, including certain LNTPs with several customers that support large solar and battery facilities and a planned natural gas-fired power plant, and service agreements for other power and industrial facilities.

The Kilroot Project Loss

There have been a number of challenges related to the Kilroot project that have adversely impacted our ability to execute as expected, including supply chain delays, material changes to the project, the COVID-19 omicron outbreak, the war in Ukraine and extreme weather. In addition, unresolved variances and claims have disrupted the execution of the project and harmed the cash flow of this project. Unresolved project-related matters continue to meaningfully impact the contract, our costs and the project schedule negatively. During the third quarter of Fiscal 2024, APC’s estimates of the unfavorable financial impacts due to difficulties on the Kilroot project escalated substantially. APC conducted an updated and comprehensive review of the costs of the efforts to complete the remaining contract work and recorded a contract loss. Our accounting reflects that the estimated costs of APC at the completion of the Kilroot project will exceed projected revenues by $10.0 million. The amount of this loss, plus the unfavorable adjustment of estimated gross profit of approximately $3.6 million recognized in the prior fiscal year in connection with the project, was reflected in our operating results for Fiscal 2024.

The project owner has provided notice to us asserting that it is entitled to schedule liquidated damages (the “LDs”). We do not agree with the project owner, who has continued to deny any of our entitlements to an extension of time related to owner delays, force majeure and other events, and we have not recorded any liability related to the LDs. We have identified and/or submitted claims, in excess of the amount of our recorded contract loss and the LDs, that we have not included in contract value at January 31, 2024. APC is continuing all efforts to resolve open variations, claims and an appropriate extension of time to mitigate these losses and improve the final results of the project. APC shall vigorously pursue all of its rights under the contract including through legal means if necessary.

APC has substantially completed the scope of its work and has turned over one of two power units to the owner, with the second power unit expected to be turned over imminently. First fire was achieved for one of the units in March 2024. APC continues to support commissioning efforts and is completing final works and punch list items, which is expected to be finished during the first half of Fiscal 2025. The determination of the amount of the loss identified above includes management’s estimates of the level of effort, and the associated costs, required for APC to complete the project. There can be no assurance that future unanticipated problems on this project will not result in APC incurring costs, that may be meaningful, in excess of those currently estimated for the completion of the contracted work or suffering unfavorable contract variations.

Operating Result Trends

The loss recorded for the Kilroot project in Fiscal 2024 obscured the otherwise strong operating performances of GPS, TRC, SMC and the Irish operations of APC. Consolidated revenues did increase by approximately 26% for Fiscal 2024.

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Consolidated gross profit of $80.8 million for Fiscal 2024, however, was directly impacted by the $13.6 million loss recorded for the Kilroot project. As we continue to grow, the mix of our revenues may become more diversified with the addition of lower risk, lower margin projects that would result in lower overall gross margin percentages. However, our gross profit amounts will continue to grow as we reduce the overall risk profile of our project portfolio.

Market Outlook

Natural Gas Power

The overall growth of our power business has been substantially based on the number of combined cycle gas-fired power plants built by us, as many coal-fired plants have been shut down in the U.S. In 2010, coal-fired power plants accounted for about 45% of net electricity generation in the U.S. For 2023, coal fueled approximately 17% of net electricity generation. It has been reported that the average age of the active plants in the coal-fired fleet approximates 45 years old with an average life span of 50 years; the last coal-fired power plant built in the U.S. was constructed in 2015. On the other hand, natural-gas fired power plants provided approximately 42% of the electricity generated by utility-scale power plants in the U.S. in 2023, representing an increase of 70% in the amount of electrical power generated by natural gas-fired power plants, which provided approximately 24% of net electricity generation for 2010.

In the reference case of its most recently published Annual Energy Outlook released in March 2023, the EIA projects that economic growth paired with increasing electrification in end-user sectors will result in notable growth of electricity demand in the U.S. through 2050. Declining capital costs for solar panels, wind turbines and battery storage, as well as government subsidies like those included in the Inflation Reduction Act of 2022 (the “IRA”), will result in renewables becoming increasingly cost effective compared with the alternatives when the costs of building new power capacity are considered. Renewables are increasingly meeting power demand through 2050 as they become more competitive with natural gas, coal and nuclear power. As a result of the renewables growth, U.S. coal-fired generation capacity is forecasted to decline sharply to represent approximately 8% of net electricity generation for 2030, with a gradual decline thereafter.

The historic decline in the use of coal as a power source in the U.S. was caused, to a significant extent, by the plentiful supply of domestic and generally inexpensive natural gas which made it the fuel of choice for power plant developers over this period. The pace of the historic increase in the preference for natural gas as an electricity generating fuel source also was energized, in part, by environmental activism and restrictive regulations targeting coal-fired power plants.

However, the headwinds confronting a significant resurgence in the pace of planning new developments of gas-fired power plants are strong. The environmentalist opposition against coal-fired power generation expanded meaningfully to target all fossil fuel energy projects, including both power plants and pipelines, and evolved into powerful support for renewable energy sources. Various cities, counties and states have adopted clean energy and carbon-free goals or objectives with achievement expected by a certain future date, typically 10 to 30 years out. These aspirational goals may increase the risk of a new power plant becoming a stranded asset long before the end of its otherwise useful economic life, a risk that potential equity capital providers may be unwilling to take. The difficulty in obtaining project equity financing and the other factors identified above, may be adversely impacting the planning and initial phases for the construction of new natural gas-fired power plants. Lenders, who have become more wary of funding fossil-fuel ventures as environmental, social and governance ideals influence financing decisions, may be generally unwilling to provide capital for energy projects to increase the domestic production and transmission of oil and natural gas. In addition, insurance underwriters may require oil and gas industry clients to implement plans to reduce methane emissions, that are among the most severe greenhouse gases, and will not provide insurance coverage for oil and gas projects in government-protected conservation areas that do not allow for sustainable use.

Solar and Wind Power

The net amount of electricity generation in the U.S. provided by utility-scale solar photovoltaic and wind facilities continues to rise. Together, such power facilities provided approximately 12%, 13% and 15% of the net amount of electricity generated by utility-scale power facilities in 2021, 2022 and 2023, respectively. EIA projects that new wind and photovoltaic solar capacity will continue to be added to the utility-scale power fleet in the U.S. at a brisk pace substantially attributable to declines in the amount of renewable power plant component and power storage costs, an increase in the scale of energy storage capacity (i.e., battery farms and other energy storage technologies), the availability of valuable tax credits and the overall political commitment to renewable energy.

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The surge in renewable energy is propelled by significant factors, including a nearly 90% reduction in solar power costs and a two-thirds decrease in onshore wind costs between 2009 and 2023. These cost reductions, driven by technological advancements, have led to widespread global adoption. The EIA indicated that for 2024, of the approximately 62.8 gigawatts of new utility-scale electric-generating capacity that is planned to be added to U.S. power grids, approximately 71% will come from solar and wind facilities. However, challenges persist, notably in offshore wind sectors facing cost overruns and supply chain issues, resulting in major offshore wind projects being delayed or cancelled.

The Power Grid Transition

Throughout the U.S., the risk of electricity shortages grows as the retirement of traditional power plants outpaces their replacement by renewable energy and battery storage. The strain on power grids mounts as the U.S. makes the historic transition from conventional power plants fueled by coal and natural gas to renewable forms of energy such as solar and wind power. Electric-grid operators are warning that power-generating capacity is struggling to keep up with demand, a gap that could lead to additional rolling blackouts during heat waves or other peak power periods.

The challenge is that solar and wind farms do not produce electricity at all times and they need large batteries to store their output for later use. While large battery storage capacity is under development, regional grid operators have warned that the pace may not be fast enough to offset the closures of traditional power plants that can work around the clock.

PJM published a study in February 2023 that supported the growing concern that the reliability of power grids is being eroded by the rush to renewable power. Its research highlighted three trends that present increasing reliability risks during the transition due to a potential timing mismatch between load growth, resource retirements and the pace of new electricity generating plant additions. The study indicates that the growth rate of electricity demand in the PJM footprint is likely to increase from electrification (i.e., shifts to electric-powered automobiles, electric appliances, etc.) coupled with the proliferation of high-demand data centers in the region. Coal-fired and old gas-fired power generation facilities are being retired at a rapid pace, possibly creating the risk that such retirements may outpace the construction of new power-generating facilities as PJM’s interconnection queue includes primarily intermittent and limited-duration renewable energy resources. Given the operating characteristics of these types of facilities, PJM will need multiple megawatts of renewable power and accompanying battery storage, and improvements in the transmission network, to replace a single megawatt of thermal generation.

Accelerating the build-out of renewable energy sources and batteries has become an especially difficult proposition amid supply-chain challenges and inflation. For example, during Fiscal 2023, the highly publicized probe by the U.S. Commerce Department into whether Chinese solar manufacturers were circumventing trade tariffs on solar panels had the effect of halting imports of key components needed to build new solar farms. As a result of this probe, the U.S. determined that certain Chinese solar manufacturers were dodging U.S. tariffs by finishing their products in Cambodia, Malaysia, Thailand and Vietnam, countries that accounted for approximately 80% of solar panel supplies. In August 2023, the U.S. Commerce Department imposed tariffs on solar imports from Southeast Asia. Critics of this action claim that the tariffs will scramble supply chains, delay projects and reduce profits for solar farm developers.

Additionally, solar and wind energy plant developers continue to confront the problems caused by grid congestion, often unsuccessfully. Many of these projects have been canceled because renewable plants need to be sited where the resources are optimal, often in remote locations where the transmission systems are not robust as power is consumed substantially in urban areas. The costs associated with the necessary grid upgrades may be prohibitive.

U.S. offshore wind projects progress inconsistently, facing challenges in the areas of environmental and fishery impacts, grid connection complexities, transmission planning, federal permitting processes and rising interest rates. Further, U.S. projects are confronted by shipping regulations that may limit the ability of developers to replicate successful European erection models. Commitments to sell power at a fixed price in an environment of rising inflation and interest rates have challenged the finances of many offshore wind projects, and as a result several prominent projects have been delayed or cancelled. Proponents of clean energy also face political challenges from constituencies who oppose the impacts to wildlife and the environment that may be caused by clean energy infrastructure projects.

Nuclear Power

Electricity generation from commercial nuclear power plants in the U.S. began in 1958. Over the last several decades, the number of operating nuclear reactors has declined. At the end of August 2023, the U.S. had 93 operating commercial

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nuclear reactors at 54 nuclear power plants in 28 states. The average age of these nuclear reactors is approximately 42 years old with most plants authorized to operate for another 20 years. Few nuclear reactors have been constructed in the U.S. over the last several decades. Construction of the Vogtle Units 3 and 4 located in Georgia began in 2009. After lengthy construction delays and billions of dollars of cost overruns, Vogtle Unit 3 commenced commercial operation in August 2023, which marks the first nuclear reactor commissioned in the U.S. since the Tennessee Valley Authority’s Watts Bar 2 in 2016, which was twenty years after the previous one began operation.

Renewed interest in nuclear power could result in the construction of carbon-free, electricity generation stations in the U.S. that would use smaller and more economical nuclear reactors. The deployment of small modular reactors could mean lower construction and electricity costs through the use of simpler power plant designs, standardized components and passive safety measures. Such plants could be built in less time than larger plants, utilize less space and represent a viable choice for reliable power to offset the intermittencies of renewable power sources. The increase by the U.S. in its use of nuclear power for electricity generation could have unfavorable effects on the demand for new natural gas-fired and additional renewable energy facilities in the future, but could provide balance-of-plant construction opportunities for GPS.

Hydrogen Power

It is important to note that the plans for certain natural gas-fired power plant projects include the integration of hydrogen-burning capabilities. While the plants will initially burn natural gas alone, it is planned by the respective project owners that the plants will eventually burn a mixture of natural gas and green hydrogen, thereby establishing power-generation flexibility for these plants. Operational testing of gas turbines fueled with renewable hydrogen have been successful. We believe this pairing is a winning combination that provides inexpensive and efficient power, enhances grid reliability and addresses clean-air concerns. The building of state-of-the-art power plants with flex-fuel capability replaces coal-fired power plants in the short term with relatively clean gas-fired electricity generation. Further, such additions to the power generation fleet provide the potential for the plants to burn 100% green hydrogen gas, which would provide both base load power and long duration back-up power, when the sun is not shining or the wind is not blowing, for extended periods of time and without certain harmful air emissions.

The Regulatory Landscape

We believe that significant uncertainty relates to the policies of the current U.S. presidential administration. President Biden proposes to make the electricity production in the U.S. carbon free by 2035 and to put the country on the path to achieve net zero carbon emissions by 2050.

In August 2022, President Biden signed the IRA, a climate and healthcare bill that funds hundreds of billions of dollars in tax subsidies intended to combat climate change among other measures. According to certain commentary, the legislation will cause investment in technologies needed for leaner production and the use of fuel types, including hydrogen, nuclear, renewables and fossil fuels. However, it appears that receipt of the majority of the tax subsidies will be conditioned on the extent that taxpayers “buy American” and/or pay prevailing wages, among other requirements. Existing supply chains and skilled labor pools may lack the capacity to meet the demand that the incentives are intended to create. Therefore, the subsidies may not provide the intended economic incentives to renewable and other energy project owners.

In May 2023, the Biden administration proposed new rules for the Environmental Protection Agency (the “EPA”) that are intended to drastically reduce greenhouse gases from coal- and gas-fired power plants that officials admit will cost such plants billions of dollars to comply fully by 2042. The proposed rules would give owners of energy plants flexibility in choosing the means to achieve the emission targets. Alternatives could include the installation of carbon-capture systems or the blending of cleaner fuels such as hydrogen. Opponents to the rules posit that the technology needed to meet such emissions targets, particularly for carbon capture and storage as well as hydrogen blending, is not yet commercially available, and as a result, makes compliance uncertain. Additionally, environmental groups and landowners have challenged plans to erect pipelines intended to transfer carbon emissions to storage locations. In March 2024, the EPA signaled it will narrow the scope of the rules by excluding existing natural gas power plants. Final rules are expected in 2024.

In June 2023, President Biden signed the debt ceiling bill which included reforms for certain elements of the permitting process for energy projects. The bill imposes certain timelines for federal agencies to review and to approve elements of major energy projects and includes provisions designating a single agency to take the lead on the environmental review

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process. Such streamlining of the current permitting process for energy generating facilities could ease certain constraints on the power industry.

Capacity Auctions

Most of our recently completed and awarded EPC service contracts relate to the construction of natural gas-fired power plants located within the Mid-Atlantic geographic footprint of PJM, which operates a capacity market to ensure long-term grid reliability by securing the appropriate amount of power supply resources needed to meet predicted future energy demands in its region. Capacity payments represent meaningful portions of the revenue streams of qualifying power plants. Annual capacity auctions since 2021 have suffered delays that, once held, resulted in lower prices than previous auctions. In June 2023, FERC issued an order accepting delays in future capacity auctions so that market design rule changes proposed by stakeholders might be implemented for all future auctions. In January 2024, FERC approved only one component of PJM’s two-part proposal for its capacity auction reform.

Uncertainty in this market, including the difficulties experienced by PJM in implementing a capacity auction design that all of its stakeholders consider to be fair, the repeated capacity auction delays, and the shrinking annual capacity auction prices, may discourage potential power plant owners from commencing the development of new power plants in this area thereby reducing potential new business opportunities for us.

Outlook for Natural Gas-Fired Power Plants

Despite the headwinds, we believe that the lower operating costs of natural gas-fired power plants, the higher energy generating efficiencies of modern gas turbines, and the requirements for grid resiliency should sustain the demand for modern combined cycle and simple cycle gas-fired power plants in the future. Natural gas is relatively clean burning, generally cost-effective, dependable and abundant. New gas-fired power plants incorporate major advances in gas-fired turbine technologies that have provided increased power plant efficiencies while providing the quick starting capabilities and the reliability that are necessary to balance the inherent intermittencies of solar and wind power plants.

We believe that the benefits of natural gas as a source of power are compelling, especially as a complement to the deployment of solar and wind powered energy sources, and that the future long-term prospects for natural gas-fired power plant construction remain generally favorable as natural gas continues to be the primary source for power generation in our country. The future availability of less carbon-intense, higher efficiency and inexpensive natural gas in the U.S. should be a significant factor in the economic assessment of future power generation capacity additions, although the pace of new opportunities emerging may be restrained and the starts of awarded EPC projects may be delayed or cancelled due to the challenges described above.

It has been stated that the scramble for electricity, regardless of source, caused by the Russian invasion of Ukraine clarified that the 100% transition to renewable energy is in the distant future and has prompted, in part, renewed interest in not only carbon capture techniques, but carbon removal technologies as well. Carbon capture processes grab carbon from smokestacks and other sources of dense greenhouse gases, thereby reducing harmful emissions. Carbon-removal technologies are more demanding as they remove carbon out of the more diffuse open air in order to store it for centuries. Governments, including the U.S., are taking initial steps to boost this industry. The success of this industry could reduce the climate-change fear associated with natural gas-fired power plants. We intend to execute an “all-of-the-above” approach in pursuing the construction of future facilities that support the energy transition, which we see as a continuation of our historical commitment to building cleaner energy plants.

International Power Markets

The foregoing discussion in this “Market Outlook” has focused on the state of the domestic power market as the EPC services business of GPS historically provides the predominant portion of our revenues. However, overseas power markets provide important new power construction opportunities for APC especially across Ireland and the U.K.

While both of these countries are committed to the increase in energy consumption sourced from the sun and wind on the pathway to net zero emissions, there is a recognition that these sources of electrical power are inherently variable. Other technologies will be required to support these power sources and to provide electricity when power demands exceed the amount of electricity supplied by these renewables. The existence of the necessary power reserve will require conventional generation sources, typically natural gas-fired power plants in Ireland but including nuclear power in the U.K.

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The Irish government has issued a policy statement on the security of the electricity supply in Ireland which confirms the requirement for the development of new support technologies to deliver on its commitment to have 80% of the country’s electricity generated from renewables by 2030. The report emphasizes that this will require a combination of conventional generation (typically powered by natural gas), interconnection to other jurisdictions, demand flexibility and other technologies such as battery storage and generation from renewable gases. The Irish government has approved that the development of new conventional generation (including gas-fired and gasoil distillate-fired generation) is a national priority and should be permitted and supported in order to ensure the security of electricity supply while supporting the growth of renewable electricity generation.

Further, the Irish government recognizes that the successful development of data centers in the country is a key aspect in promoting Ireland as a digital economy hot-spot in Europe. The stewards of the electricity supply in Ireland acknowledge that the large increase in electricity demand presented by the growth of the data center industry represents an evolving, significant risk to the security of the supply. During Fiscal 2023, APC completed a project to install natural gas-fired power generation for a major data center in the Dublin area.

Recently, the government of the U.K. expressed support for new gas-fired power plants to offset the remaining coal-fired plant retirement, the retirement of aging gas plants, and the intermittency of renewable energy plants. Prime Minister Rishi Sunak stated that he would not gamble with energy security despite U.K. plans to decarbonize the power system by 2035. His secretary of state for energy security echoed these sentiments with a speech in which she stated that she expected to warn of blackouts unless there is sufficient gas-fired capacity to provide back-up for intermittent renewables. Her comments also expressed hope that new gas plants will be accompanied with the potential ability to burn 100% hydrogen or be fitted with carbon capture and storage technologies. Of course, the recency of these pronouncements means that it is too soon to expect energy policy shifts or the announcement of plans for specific new gas-fired power plants in the U.K. Further, the outlook for Mr. Sunak’s government is shaky and the opposition party is much more bullish on decarbonization.

Nonetheless, APC is actively pursuing other new business opportunities in both the renewable and support sectors of power generation with its existing and new clients in both countries. Over the last three years, APC has increased its activities and currently has multiple projects under execution. GPS has been providing top management guidance and project management expertise to APC during this period. APC has also provided experienced resources to GPS on several of its EPC services contracts in the U.S. These recent experiences have demonstrated that the two companies can combine and share resources effectively to leverage capacity and opportunities. We believe that GPS and APC working together is a competitive advantage as we pursue emerging new business opportunities in Ireland and the U.K. GPS is teaming with APC in the performance of the Shannonbridge Power Project.

The EPC Competitive Landscape

We are committed to the rational pursuit of new construction projects, including those with overseas locations and unique deployments of power-generation turbines, and the future growth of our revenues. This may result in additional decisions to make investments in the development and/or ownership of new projects. Because we believe in the strength of our balance sheet, we are willing to consider certain opportunities that include reasonable and manageable risks in order to assure the award of the related EPC or equipment installation services contracts to us.

The competitive landscape for our core EPC services business related to natural gas-fired power plants in the U.S. remains dynamic, although there are fewer competitors for new gas-fired power plant EPC services project opportunities. Several major competitors have exited the market for a variety of reasons or have been acquired. Others have announced intentions to avoid entering into fixed-price contracts. Nonetheless, the competition for new utility-scale gas-fired power plant construction opportunities is fierce and still includes multiple global firms. We believe that the Company has a reputation as an accomplished, dependable and cost-effective provider of EPC and other large project construction contracting services. With the proven ability to deliver completed power facilities, particularly combined cycle, natural gas-fired power plants, we are focused on expanding our position in the power markets of the U.S., Ireland and the U.K. where we expect investments to be made based on forecasts of electricity demand covering decades into the future. We believe that our expectations are valid and that our plans for the future continue to be based on reasonable assumptions.

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Industrial Construction Services Outlook

TRC was founded in 1977, initially focused on the fabrication of piping systems and pressure vessels. Prior to our acquisition of TRC in 2015, it expanded its business to include industrial field services with a concentration on turnarounds, outage support, renovations, repairs and maintenance projects. Since the acquisition, TRC has narrowed the focus of its field services to emphasize industrial construction projects. During Fiscal 2023, TRC consolidated its metal fabrication plants and support structures into one industrial fabrication and warehouse facility near Greenville, North Carolina, which is centrally located within its primary geographic market. The consolidation reduced fixed costs and notably streamlined the business, which has permitted TRC to primarily focus on its field service construction opportunities.

Industrial field services typically represent the majority of TRC’s annual revenues with the remaining revenues contributed by projects consisting solely of metal fabrication. Recent and current major customers of TRC include Nutrien Ltd., the global fertilizer company; Jacobs Solutions Inc., an international engineering and construction firm that is building a significant biotechnology manufacturing facility in the research triangle area of North Carolina; and North America’s largest forest products companies such as Weyerhaeuser Company, International Paper and Domtar Corporation; and various other industrial companies. These relationships demonstrate that TRC is a trusted industrial services provider to blue chip customers from around North America, and from countries like France, Germany, Denmark, Japan, Belgium and Australia, that are expanding or locating new production facilities in TRC’s geographic region.

As stated above, the business footprint for TRC encompasses the Southeast region of the U.S. where there are many local and state governments that welcome industrial production facilities with ideal locations and with serious economic development programs and incentives. The national focus on infrastructure improvements, biotechnology advancements, energy storage and clean water have resulted in firms that are focused on these trends recently choosing TRC to participate in major construction projects in the region. Other important factors and trends include low corporate state tax rates, favorable labor migration patterns, the surface transportation infrastructure and the ready access to modern seaports.

Economic data supports our belief that TRC is ideally located in a leading manufacturing growth area of the U.S., which should continue to provide it with project opportunities going forward that will expand its business and industrial construction capabilities. The Dodge Construction Starts report for 2024 forecasts that total construction in the U.S. will increase by 7% in 2024, with a 16% increase in the manufacturing category. The FMI Construction Put-in-Place Forecast for 2024 predicts that construction activity in the manufacturing sector will increase by over 15% in 2024. This data suggests that manufacturing construction will be a robust market as the economy moves into 2024. Despite headwinds such as material price volatility and rising labor costs, skilled labor shortages, high interest rates and tighter lending standards, it is likely that 2024 will see a boost to construction associated with manufacturing, as well as the transportation and clean energy infrastructures, as funds from three key pieces of national legislation passed in 2021 and 2022 are expected to flow into the industry. These bills include the Infrastructure and Jobs Act, the IRA and the Creating Helpful Incentives to Produce Semiconductors Act, and appear to be sustaining high construction industry confidence for 2024 and the future beyond.

For Fiscal 2024, the revenues of TRC increased by approximately 54% to $142.8 million and the project backlog of TRC has grown by over 175% since January 31, 2022 to approximately $127.5 million as of January 31, 2024.

Comparison of the Results of Operations for the Years Ended January 31, 2024 and 2023

We reported net income attributable to our stockholders of $32.4 million, or $2.39 per diluted share, for Fiscal 2024. For the prior fiscal year, we reported net income attributable to our stockholders of $33.1 million, or $2.33 per diluted share. The following schedule compares our operating results for Fiscal 2024 and Fiscal 2023 (dollars in thousands):

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Revenues

Power Industry Services

The revenues of the power industry services business increased by 20.3%, or $70.3 million, to $416.3 million for Fiscal 2024 compared with revenues of $346.0 million for Fiscal 2023, as the current year construction activities increased for the Trumbull Energy Center, the Shannonbridge Power Project, the ESB FlexGen Peaker Plants and the Midwest Solar and Battery Projects. The increase in revenues between years was partially offset by decreased construction activities associated with the Guernsey Power Station project, the Maple Hill Solar Facility and the Equinix data center project, as those projects are generally near or at completion. The revenues of this business represented approximately 72.6% of consolidated revenues for Fiscal 2024 and 76.0% of consolidated revenues for the prior year. The project backlog amounts for the power industry services reportable segment as of January 31, 2024 and 2023 were $0.6 billion and $0.7 billion, respectively.

Industrial Construction Services

The revenues of industrial construction services increased by $50.0 million, or 53.9%, to $142.8 million for Fiscal 2024 compared with revenues of $92.8 million for Fiscal 2023. The revenues of this business represented approximately 24.9% of consolidated revenues for Fiscal 2024 and 20.4% of consolidated revenues for the prior fiscal year. The strategy to focus on larger field projects, coupled with the consolidation of the two fabrication facilities during Fiscal 2023, enhanced leadership and a positive regional business environment has resulted in increased revenues and the ability to maintain project backlog at $127.5 million as of January 31, 2024 as compared to $123.5 million as of January 31, 2023.

Telecommunications Infrastructure Services

The revenues of telecommunications infrastructure services were $14.3 million for Fiscal 2024 compared with revenues of $16.2 million for Fiscal 2023.

Cost of Revenues

Due primarily to the increase in consolidated revenues for Fiscal 2024 compared with revenues for Fiscal 2023, consolidated cost of revenues also increased. These costs were $492.5 million and $368.7 million for Fiscal 2024 and Fiscal 2023, respectively.

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For Fiscal 2024, we reported a consolidated gross profit of approximately $80.8 million, which represented a gross profit percentage of approximately 14.1% of corresponding consolidated revenues. Consolidated gross profit was adversely impacted by the $13.6 million loss recorded for the Kilroot Power Station project in the current fiscal year. However, the effect of the contract loss was meaningfully offset by the profits earned on the performance of other projects by each of our four operating companies, including APC.

The gross profit for the period reflected primarily the profit contributions of efficient construction activities related to the major projects of the power industry services reporting segment, which was adversely impacted by the loss recorded in Fiscal 2024 related to the Kilroot Power Station. The gross profit percentages of corresponding revenues for the power industry services, industrial construction services and telecommunications infrastructure services segments for Fiscal 2024 were 14.1%, 12.9% and 26.5%, respectively.

For Fiscal 2023, we reported a consolidated gross profit of approximately $86.4 million, which represented a gross profit percentage of approximately 19.0% of corresponding consolidated revenues. The gross profit percentages of corresponding revenues for the power industry services, industrial construction services and telecommunications infrastructure services segments for Fiscal 2023 were 19.8%, 15.9% and 18.4%, respectively.

Selling, General and Administrative Expenses

Selling, general and administrative expenses were $44.4 million and $44.7 million for Fiscal 2024 and Fiscal 2023, respectively, representing 7.7% and 9.8% of consolidated revenues for the corresponding periods, respectively.

Other Income, Net

For Fiscal 2024 and Fiscal 2023, the net amounts of other income were $12.5 million and $4.3 million, respectively, which represented an increase of 188.0% between the comparable periods. For Fiscal 2024 and Fiscal 2023, this line item included income in the amounts of $14.1 million and $3.4 million, respectively, earned on invested funds, as investment yields and average balances of invested funds have increased meaningfully between periods. Offsetting the increase of other income between periods is the wire-transfer fraud loss of $3.0 million that occurred in the first quarter of Fiscal 2024, of which $0.5 million in funds were recovered through legal efforts and insurance proceeds (see Note 18 to the accompanying consolidated financial statements). This line item also includes our share of the net income reported from our solar tax credit investments in the amount of $1.1 million for Fiscal 2023, with the corresponding amount for Fiscal 2024 being insignificant (see Note 12 to the accompanying consolidated financial statements).

Income Tax Expense

We recorded income tax expense for Fiscal 2024 in the net amount of approximately $16.6 million primarily due to our reporting pre-tax income for financial reporting purposes in the amount of $48.9 million for the year. Our annual effective income tax rate for Fiscal 2024 was 33.9%. This tax rate differed from the statutory federal tax rate of 21% due to various factors with unfavorable income tax effects. Most significantly, the net operating loss of APC’s subsidiary in the U.K., where the loss on the Kilroot Power Station project was recorded, was not tax effected with benefit. In addition, the actual effective tax rate reflected the effect of state income taxes, and the unfavorable effects of several nondeductible expense amounts, including certain executive compensation, meals, and other travel expenses, and an unfavorable adjustment to deferred taxes by APC. Partially offsetting these unfavorable effects were the foreign tax rate differential, which lowered the overall effective tax rate and the investment tax credit effect recorded in Fiscal 2024 related to our solar fund investments.

We recorded income tax expense for Fiscal 2023 in the net amount of approximately $11.3 million primarily due to our reporting pre-tax income for financial reporting purposes in the amount of $46.0 million for the year. Our annual effective income tax rate for Fiscal 2023 was 24.6%. This tax rate differed from the statutory federal tax rate of 21% due primarily to the effects of state income taxes, nondeductible executive compensation and the unfavorable effects of our settlement with the IRS related to research and development credits at an amount lower than we had previously recorded, partially offset by the favorable recognition of tax benefits related to research and development tax credits recognized in the current year and favorable deferred tax adjustments. See Note 12 to the accompanying consolidated financial statements.

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Net Income Attributable to Non-Controlling Interest

As discussed above, we recorded a gain of $1.6 million related to the VIE settling on amounts owed for certain previously impaired development costs during Fiscal 2023, which was attributed to non-controlling interest. See Note 15 to the accompanying consolidated financial statements.

Liquidity and Capital Resources as of January 31, 2024

At January 31, 2024 and 2023, our balances of cash and cash equivalents were $197.0 million and $173.9 million, respectively, which represented an increase of $23.1 million between years.

The net amount of cash provided by operating activities for Fiscal 2024 was $116.9 million. Our net income for Fiscal 2024, adjusted favorably by the net amount of non-cash income and expense items, represented a source of cash in the total amount of $38.9 million. The increase in the balance of contract liabilities in the amount of $84.8 million represented a source of cash during the year as net billings were received in advance of the satisfaction of performance obligations on certain of our contracts. These favorable balance sheet account changes primarily related to the increases in contract liabilities for the Trumbull Energy Center and the Shannonbridge Power Project, partially offset by decreases in contract liabilities related to the Kilroot Power Station and the ESB FlexGen Peaker Plants. Additionally, the increase in the combined level of accounts payable and accrued expenses in the amount of $14.8 million represented a source of cash for the year. The decrease in accounts receivable in the amount of $2.8 million also represented a source of cash for the year. The increases in the balances of contract assets and prepaid expenses and other assets in the amounts of $23.4 million and $1.0 million, respectively, represented uses of cash during the year.

During Fiscal 2024, our primary source of cash from investing activities was the net maturities of CDs issued by the Bank, in the amount of $44.8 million. We used $104.5 million to invest in available-for-sale securities, consisting of U.S. Treasury notes and a U.S. corporate debt security. We also used $2.8 million to make capital expenditures, and we made a cash investment of $5.1 million in a solar tax credit entity during the year.

We used $26.1 million cash in financing activities during Fiscal 2024, including $12.5 million used to repurchase shares of common stock pursuant to our Share Repurchase Plan and $14.7 million used for the payment of regular cash dividends. Lastly, during Fiscal 2024, we received net $1.1 million of proceeds from the settlement of share-based awards. As of January 31, 2024, there were no restrictions with respect to intercompany payments between GPS, TRC, APC, SMC and the holding company.

During Fiscal 2023, our balance of cash and cash equivalents declined by a net amount of $176.6 million.

The net amount of cash used in operating activities for Fiscal 2023 was $30.1 million. However, our net income for Fiscal 2023, adjusted favorably by the net amount of non-cash income and expense items, represented a source of cash in the total amount of $39.0 million. The increases in accounts receivable, contract assets and other assets in the amounts of $23.2 million, $19.9 million and $3.3 million, respectively, represented uses of cash during Fiscal 2023. Additionally, the reduction in the balance of contract liabilities in the amount of $31.6 million represented a use of cash during Fiscal 2023 to fund, on a net basis, the satisfaction of performance obligations on certain of our contracts. These unfavorable balance sheet account changes primarily related to the decline in the construction activity of the Guernsey Power Station project, partially offset by increases in contract liabilities related to the Trumbull Energy Center and several APC projects. The increase in the combined level of accounts payable and accrued expenses in the amount of $9.1 million, represented a source of cash for Fiscal 2023.

Non-operating activities during Fiscal 2023 used cash to increase the level of our short-term investments, which consisted entirely of CDs issued by the Bank, by $59.8 million and to make capital expenditures in the amount of $3.4 million. We also used $82.8 million cash in financing activities during Fiscal 2023, including $68.2 million used to repurchase shares of common stock pursuant to our Share Repurchase Plan, and $14.0 million used for the payment of regular cash dividends.

At January 31, 2024, a portion of our balance of cash and cash equivalents was invested in a money market fund with most of its net assets invested in cash, U.S. Treasury obligations, other obligations issued by U.S. Government agencies and sponsored enterprises, and repurchase agreements secured by U.S. government obligations. The major portion of our domestic operating bank account balances are maintained with the Bank. We do maintain certain Euro-based bank accounts in Ireland and certain pound sterling-based bank accounts in the U.K. in support of the operations of APC.

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In order to monitor the actual and necessary levels of liquidity for our business, we focus on working capital, or net liquidity, in addition to our cash balances. Our net liquidity increased by $8.7 million to $244.9 million as of January 31, 2024 from $236.2 million as of January 31, 2023, due primarily to our net income for the fiscal year, partially offset by common stock repurchases and the payment of cash dividends. As we have no debt service, as our fixed asset acquisitions in a reporting period are typically low, and as our net liquidity includes our short-term investments and available-for-sale investments, our levels of working capital are not subjected to the volatility that affects our levels of cash and cash equivalents.

During April 2021, we amended our Credit Agreement with the Bank which extended its expiration date to May 31, 2024 and reduced the borrowing rate. On March 6, 2023, we entered into the Second Amendment to the Credit Agreement. The Second Amendment modified the Credit Agreement primarily to replace the interest pricing with a rate of SOFR plus 1.6% and add SOFR successor rate language. The Credit Agreement, as amended, includes the following features, among others: a lending commitment of $50.0 million including a revolving loan and an accordion feature which allows for an additional commitment amount of $10.0 million, subject to certain conditions. Additionally, the Credit Agreement, as amended, continues to include customary terms, covenants and events of default for a credit facility of its size and nature. Prior to the expiration of the current term of the Credit Agreement, we expect to reach agreement with the Bank to amend and extend it.

We may also use the borrowing ability to cover other credit instruments issued by the Bank for our use in the ordinary course of business as defined by the Bank. At January 31, 2024, we had no outstanding borrowings, but the Bank has issued a letter of credit in the total outstanding amount of $9.3 million related to the Kilroot project of APC discussed above.

We have pledged the majority of our assets to secure the financing arrangements. The Bank’s consent is not required for acquisitions, divestitures, cash dividends or significant investments as long as certain conditions are met. The Credit Agreement, as amended, requires that we comply with certain financial covenants at our fiscal year-end and at each fiscal quarter-end, and includes other terms, covenants and events of default that are customary for a credit facility of its size and nature, including a requirement to achieve positive adjusted earnings before interest, taxes, depreciation and amortization, as defined, over each rolling twelve-month measurement period. At January 31, 2024, we were compliant with the covenants of the Credit Agreement, as amended.

In the normal course of business and for certain major projects, we may be required to obtain surety or performance bonding, to provide parent company guarantees, or to cause the issuance of letters of credit (or some combination thereof) in order to provide performance assurances to clients on behalf of one of our subsidiaries.

If our services under a guaranteed project would not be completed or would be determined to have resulted in a material defect or other material deficiency, then we could be responsible for monetary damages or other legal remedies. As is typically required by any surety bond, we would be obligated to reimburse the issuer of any surety bond provided on behalf of a subsidiary for any cash payments made thereunder. The commitments under performance bonds generally end concurrently with the expiration of the related contractual obligation. Not all of our projects require bonding.

As of January 31, 2024 and 2023, the estimated amounts of our unsatisfied bonded performance obligations, covering all of its subsidiaries, were approximately $0.5 billion and $0.6 billion, respectively. In addition, as of January 31, 2024 and 2023, the outstanding amounts of bonds covering other risks, including warranty obligations related to completed activities, were not material.

We have also provided a financial guarantee up to $3.6 million to support certain project developmental efforts. Any estimated loss related to this guarantee was recorded during Fiscal 2022.

When sufficient information about claims related to performance on projects would be available and monetary damages or other costs or losses would be determined to be probable, we would record such losses. As our subsidiaries are wholly-owned, any actual liability related to contract performance is ordinarily reflected in the financial statement account balances determined pursuant to the Company’s accounting for contracts with customers. Any amounts that we may be required to pay in excess of the estimated costs to complete contracts in progress as of January 31, 2024 are not estimable.

In prior years, we made investments in limited liability companies that make equity investments in solar energy projects that are eligible to receive energy tax credits, for which we have received substantially all of the income tax benefits

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associated with those investments. In Fiscal 2024, we made an investment of approximately $5.1 million cash in a solar tax credit entity, and as of January 31, 2024, we have $3.3 million remaining of cash investment commitments related to this solar fund, which we expect to make during Fiscal 2025. It is likely that we will evaluate opportunities to make other solar energy investments of this type in the future.

We believe that cash on hand, our cash equivalents, cash that will be provided from the maturities of short-term investments and other debt securities and cash generated from our future operations, with or without funds available under our Credit Agreement, will be adequate to meet our general business needs in the foreseeable future. In general, we maintain significant liquid capital in our consolidated balance sheet to ensure the maintenance of our bonding capacity and to provide parent company performance guarantees for EPC and other construction projects.

However, any significant future acquisition, investment or other unplanned cost or cash requirement, may require us to raise additional funds through the issuance of debt and/or equity securities. There can be no assurance that such financing will be available on terms acceptable to us, or at all.

Contractual Obligations

During Fiscal 2024, there was no significant change in the nature or amounts of our contractual obligations. We estimate that the balance of such contractual obligations as of January 31, 2024 was less than $20.0 million. The two largest items in this estimate, operating leases and deferred compensation, are amounts included as liabilities in our consolidated balance sheet. The remainder of such obligations relate primarily to open service arrangements. Outstanding commitments represented by open purchase orders and subcontracts related to our construction contracts have not been included in the estimated amounts of contractual obligations as such amounts are expected to be funded through contract billings to customers. We do not have any significant obligations for materials or subcontracted services beyond those required to complete construction contracts awarded to us.

Special Purpose Entities

As is common in our industry, EPC contractors and third parties form joint ventures, limited partnerships and limited liability companies for purposes of executing a project or program for a project owner. These teaming arrangements are typically dissolved upon completion of the project or program.

In addition, we may obtain interests in VIEs formed by its owners for a specific purpose. The evaluation of whether such interests represent our financial control of a VIE requires analysis and judgement. In January 2018, we concluded that we were the primary beneficiary of a VIE formed by an independent firm for the purpose of developing a natural gas-fired power plant in Virginia. As a result, the VIE was included in our consolidated financial statements until the fourth quarter of Fiscal 2023, when we determined that we were no longer the primary beneficiary and we deconsolidated the entity. During Fiscal 2022, as described in Note 15 to the accompanying consolidated financial statements, we recorded an impairment loss related to the development costs associated with the project in the amount of $7.9 million, of which $2.5 million was attributed to the non-controlling interest. In Fiscal 2023, prior to deconsolidation, the VIE settled on amounts owed for certain impaired development costs and recognized a gain of $1.6 million, all of which was attributed to the non-controlling interest.

We have entered into similar support arrangements with other independent parties in the past that resulted in the successful development and our construction of three separate gas-fired power plant projects. We were paid project development fees for each project and our loans to the development entities were repaid in full plus interest. In each of these cases, we deconsolidated the corresponding VIE when we were no longer the primary beneficiary.

We may enter into other support arrangements in the future in connection with power plant development opportunities when they arise and when we are confident that providing early financial support for the projects will lead to the award of the corresponding EPC contracts to us.

Earnings before Interest, Taxes, Depreciation and Amortization (“EBITDA”)

We believe that EBITDA is a meaningful presentation that enables us to assess and compare our operating performance on a consistent basis by removing from our operating results the impacts of our capital structure, the effects of the accounting methods used to compute depreciation and amortization and the effects of operating in different income tax jurisdictions. Further, we believe that EBITDA is widely used by investors and analysts as a measure of performance.

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However, as EBITDA is not a measure of performance calculated in accordance with U.S. GAAP, we do not believe that this measure should be considered in isolation from, or as a substitute for, the results of our operations presented in accordance with U.S. GAAP that are included in our consolidated financial statements. In addition, our EBITDA does not necessarily represent funds available for discretionary use and is not necessarily a measure of our ability to fund our cash needs.

The following table presents the determinations of EBITDA for Fiscal 2024 and Fiscal 2023, respectively (amounts in thousands).

Critical Accounting Policies

Critical accounting policies are those related to the areas where we have made what we consider to be particularly subjective or complex judgments in arriving at estimates and where these estimates can significantly impact our financial results under different assumptions and conditions.

These estimates, judgments, and assumptions affect the reported amounts of assets, liabilities and equity, the disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets, liabilities and equity that are not readily apparent from other sources. Actual results and outcomes could differ from these estimates and assumptions. We do periodically review these critical accounting policies and estimates with the audit committee of our board of directors.

We consider the accounting policies related to revenue recognition on long-term construction contracts and income tax reporting to be most critical to the understanding of our financial position and results of operations.

Revenue Recognition

Our revenues are primarily derived from construction contracts that can span several quarters or years. We enter into EPC and other long-term construction contracts principally on the basis of competitive bids or in conjunction with our support of the development of power plant projects. The types of contracts may vary. However, the EPC contracts of our power industry services reporting segment, and most other large contracts awarded to our other companies, are fixed-price contracts. Revenues are recognized primarily over time as performance obligations are satisfied due to the continuous transfer of control to the project owner or other customer. The accuracy of our revenues and profit recognition in a given period depends on the accuracy of our estimates of the forecasted contract value, or transaction price, and the cost to complete the work for each project.

Central to accounting for revenues from contracts with customers is a five-step revenue recognition model that requires reporting entities to:

The guidance focuses on the transfer of the control of the goods and/or services to the customer, as opposed to the transfer of risk and rewards. Major provisions cover the determination of which goods and services are distinct and represent

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separate performance obligations, the appropriate treatment of variable consideration, and the evaluation of whether revenues should be recognized at a point in time or over time. In general, application of the rules requires us to make important judgements and meaningful estimates that may have significant impact on the amounts of revenues recognized by us for any reporting period.

Revenues from fixed price contracts, including portions of estimated gross profit, are recognized as services are provided, based on costs incurred and estimated total contract costs using the cost-to-cost approach. The cost and profit estimates are re-forecasted monthly for all significant contracts pursuant to a detailed determination and review process. The results of the process are subjected to reviews by senior management with the applicable project management personnel at each subsidiary. The intensity of the reviews may vary between projects depending on the percentage-of-completion for the projects, among other factors. The cost-to-cost method measures the ratio of costs incurred and accrued to date for each contract to the estimated, or forecasted, total cost for each contract at completion. This requires us to prepare on-going estimates of the forecasted cost to complete each contract as the project progresses. In preparing these estimates, we make significant judgments and assumptions about our significant costs, including materials, labor and equipment, and we evaluate contingencies based on possible schedule variances, major equipment delivery delays, construction delays, weather or other productivity factors.

Actual costs may vary from the costs we estimate. Variations from estimated contract costs, along with other risks inherent in fixed-price contracts, may result in actual revenues and gross profits differing from those we estimate and could result in losses on projects or other significant unfavorable impacts on our operating results for any fiscal quarter or year. If a current estimate of total contract cost indicates a loss on a contract, the projected loss is recognized in full when determined, without regard to the percentage of completion. There are a number of factors that can contribute to changes in estimated contract costs, revenues and profitability. The most significant of these are identified in the first item included in the Risks Related to our Operational Execution section of Part I, Item 1A. of this Annual Report entitled Risk Factors.

Crucial to the compliance with the accounting standard covering the recognition of revenues on contracts with customers is the identification of the promises made to the customer by us that are included in the contract. If a promise is distinct, as that concept is defined in the accounting standard, it represents a separate performance obligation. Contracts may have multiple promises. The amounts of revenue associated with each promise are recognized when, or as, the performance obligations are satisfied. However, complex contracts may include only one performance obligation if the multiple promises are not distinct within the context of the contract. For example, if the promises that could be considered distinct are interrelated or require us to perform integration so that the customer receives a complete product, the contract is considered to include only one performance obligation. Most of our long-term contracts have a single performance obligation as the promises to transfer individual goods or services are not separately identifiable from other promises within the context of the contract. Our EPC contracts require us to deliver a complete and functioning power plant, not just functioning components.

The transaction price of a contract represents the value used to determine the amount of revenues recognized as of the balance sheet date. It may reflect amounts of variable consideration, which could be either increases or decreases to the transaction price. These adjustments can be made from time-to-time during the period of contract performance as circumstances evolve related to such items as variations in the scope and price of contracts, claims, incentives and liquidated damages.

We may include an estimated amount of variable consideration in the transaction price to the extent it is probable that a significant reversal of cumulative revenues recognized on the particular contract will not occur when the uncertainty associated with the variable consideration is resolved. The Company’s determination of the amount of variable consideration to be included in the transaction price of a particular contract is based largely on an assessment of the Company’s anticipated performance and all information (historical, current and forecasted) that is reasonably available. The effect of any revisions to the transaction price on the amount of previously recognized revenues that is due to the addition or reduction of variable consideration is recorded currently as an adjustment to revenues on a cumulative catch-up basis. In the event that any amounts of variable consideration that are reflected in the transaction price of a contract are not resolved in the Company’s favor, there could be reductions in, or reversals of, previously recognized revenues. In most significant instances, modifications to our contracts do not represent the addition of new performance obligations.

Contract results may be impacted by estimates of the amounts of contract variations that we expect to receive. The effects of any resulting revisions to revenues and estimated costs can be determined at any time and they could be material. As of

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January 31, 2024 and 2023, the aggregate amounts of contract variations reflected in estimated transaction prices that were pending customer approval were $8.4 million and $11.6 million, respectively.

Substantially all of our customer contracts include the right for customers to terminate contracts for convenience as disclosed in Note 2 to the consolidated financial statements. The value of future work that companies are contractually obligated to perform pursuant to active customer contracts should not be included in the disclosure of remaining unsatisfied performance obligations when the corresponding contracts include termination for convenience clauses without substantial penalties accruing to the customers upon such terminations. In the application of this guidance, we assess whether the nature of the work being performed under contract is largely service-based and repetitive and should be considered a succession of one-month contracts for the duration of the identified term of the contract. Predominantly, our customers contract with us to construct assets, to fabricate materials or to perform emergency maintenance or outage services where we believe a substantial penalty or cost would be incurred upon a termination for convenience. We believe that in substantially all cases, there would be substantial costs incurred by a customer if it terminated a contract with us for convenience including the costs of terminating subcontracts, canceling purchase orders and returning or otherwise disposing of delivered materials and equipment. Further, to the best of management’s knowledge, the Company has never had a customer terminate a material contract with us for convenience. Therefore, our disclosure in Note 2 of the value of remaining unsatisfied performance obligations on active customer contracts represents an amount based on contracts or orders received from customers that the Company believes are firm and where the parties are acting in accordance with their respective obligations.

Our long-term contracts typically have schedule dates and other performance obligations that, if not achieved, could subject us to liquidated damages. These contract requirements generally relate to specified activities that must be completed by an established date or by achievement of a specified level of output or efficiency. Each contract defines the conditions under which a project owner may make a claim for liquidated damages. The amounts of liquidated damages owed to a project owner pursuant to the terms of a contract would represent reductions of the transaction price of the corresponding contract.

At the outset of each of the Company’s contracts, the potential amounts of liquidated damages typically are not subtracted, from the transaction price as the Company believes that it has included activities in its contract plan, and has reflected the associated costs in its forecasts of completed contract costs, that will be effective in preventing such damages. Of course, circumstances may change as the Company executes the corresponding contract. The transaction price is reduced by an applicable amount when the Company no longer considers it probable that a future reversal of revenues will not occur when the matter is resolved. In general, we consider potential liquidated damages, the costs of other related items and potential mitigating factors in determining the estimates of forecasted revenues and the adequacy of our estimates of the cost to complete contracts.

Uncertain Income Tax Positions

As we have disclosed in the “Research and Development Tax Credits” section of Note 12 to the accompanying consolidated financial statements, during Fiscal 2019, we completed a detailed review of the activities of our engineering staff on major EPC services projects in order to identify and quantify the amounts of research and development credits available to reduce prior year income taxes. This extensive study focused on the costs incurred on specific projects during the three-year period ended January 31, 2018. Based on the results of the study, we identified and estimated significant amounts of income tax benefits that were not previously recognized in our financial results for any prior year reporting period.

Under current professional accounting guidance, income tax positions must meet a more-likely-than-not recognition threshold to be recognized. Income tax positions that previously failed to meet the more-likely-than-not threshold are recognized in the first subsequent financial reporting period in which that threshold is met. Fiscal 2019 was the initial reporting period in which we had sufficient data on which to make an evaluation and to reach a conclusion on the amount of income tax credit benefits related to prior year project costs that, more likely than not, qualified as research and development costs under the Internal Revenue Code and the rules and regulations of certain states. The net amount of the credits that we recognized in income taxes during Fiscal 2019 was $16.2 million, as subsequently reduced by $0.4 million. Based on our judgement, the amount of income tax benefits related to identified research and development income tax credits that we assessed as not meeting the threshold criteria for recognition was $5.0 million.

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The research and development credits were included in amendments to our consolidated federal income tax returns for Fiscal 2016 and Fiscal 2017, that were filed in January 2019, and our consolidated federal income tax return for Fiscal 2018, that was filed in November 2018. In January 2021, the IRS issued its final revenue agents reports that disagreed with our treatment of a substantial amount of the costs that supported our claims. In March 2021, we submitted a formal protest of the findings of the IRS examiner and requested an appeal hearing.

At the conclusion of the hearing that occurred in May 2022, we agreed to accept a settlement offer from the IRS in the amount of approximately $7.9 million, before interest, which was approximately 42% of the total of our claims. As a result, we made an unfavorable adjustment to income tax expense for Fiscal 2023 in the amount of $6.2 million.

In a manner similar to the process described above, we completed a detailed review of the activities of our engineering staff on major EPC services projects in order to identify and quantify the amounts of research and development tax credits that may have been available to reduce federal income taxes for Fiscal 2022 and Fiscal 2021. As a result, we filed amended federal income tax returns for those years, including research and development tax credits in the total amount of $5.8 million. With the application of current accounting guidance, we have recognized approximately 59% of this benefit. In Fiscal 2024, we obtained an insurance policy covering our tax position in the event that we would suffer a loss related to our research and development claims.

Deferred Tax Assets and Liabilities

Our consolidated balance sheet as of January 31, 2024 includes net deferred tax assets in the amount of approximately $2.3 million. The components of our deferred taxes are presented in Note 12 to the accompanying consolidated financial statements. These amounts reflect differences in the periods in which certain transactions are recognized for financial and income tax reporting purposes.

We consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized on a jurisdiction-by-jurisdiction basis. Our ability to realize our deferred tax assets, including those related to the past NOLs incurred in the U.K. (that applicable income tax rules will allow us to use in order to offset future amounts of applicable taxable income), depends primarily upon the generation of sufficient future taxable income to allow for the realization of our deductible temporary differences. If such estimates and assumptions regarding income amounts change in the future, we may be required to record additional valuation allowances against some or all of the deferred tax assets resulting in additional income tax expense in our consolidated statement of earnings. During Fiscal 2020, a valuation allowance in the amount of $7.1 million was established against the deferred tax asset amount created by the NOL of APC’s subsidiary in the U.K. (“APC UK”). During Fiscal 2023, APC UK continued a turnaround of its operating results such that we believed it had a stable earnings history upon which APC UK could reliably forecast future profitable operations. Based on the forecast, which rested on the belief that meaningful investments would be made in the power infrastructure of the U.K. for the foreseeable future, we believed that it was more likely than not that a certain portion of the deferred tax asset would be realized. Accordingly, we reversed a portion of the corresponding allowance during Fiscal 2023 in the amount of $2.6 million. However, the unexpected difficulties with one construction project and the loss that was recorded by APC UK related to it caused management to reconsider the amount of work expected to be performed in the U.K. in the future. Accordingly, the estimate of the amount of future net earnings of APC UK available to offset its net operating loss carryforwards was reduced causing us to increase the amount of the allowance by $2.1 million in Fiscal 2024.

A deferred tax asset in the amount of $8.3 million was recorded as of January 31, 2020 associated with the income tax benefit of our domestic NOL for Fiscal 2020 without any corresponding valuation allowance. Among other changes, the CARES Act re-established a carryback period for certain losses to five years. The NOLs eligible for carryback under the CARES Act include our domestic loss for Fiscal 2020, which was approximately $39.5 million. The carryback provided a favorable rate benefit for us as the loss, which was incurred in a year where the statutory federal tax rate was 21%, has been carried back to tax years where the tax rate was higher. The net amount of this additional income tax benefit, which we recorded in Fiscal 2021, was $4.4 million. We have made the appropriate filings with the IRS requesting carryback refunds of income taxes paid in prior years. With the enactment of the CARES Act, the asset amount, which totals $12.7 million, was moved to income taxes receivable. The IRS has not completed the examination of our refund request.

At this time, we believe that the historically strong earnings performance of our power industry services segment will provide sufficient income during the years when most of our other deferred tax assets become deductible in the U.S. in order for us to realize the applicable temporary income tax differences. Accordingly, we believe that it is more likely than not that we will realize the benefit of significantly all of our net deferred tax assets.

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Recently Issued Accounting Pronouncements

See Note 1 to the accompanying consolidated financial statement for discussion of recently issued accounting pronouncements.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion summarizes the financial position of Argan, Inc. and its subsidiaries as of January 31, 2023, and the results of their operations for Fiscal 2023 and Fiscal 2022, and should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in Item 8 of this 2023 Annual Report.

Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in the Company’s Annual Report on Form 10-K for the year ended January 31, 2022, that was filed with the SEC on April 13, 2022, for a discussion of financial trends, variance drivers and other significant matters for Fiscal 2022 as compared to Fiscal 2021.

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Cautionary Statement Regarding Forward Looking Statements

The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for certain forward-looking statements. We have made statements in this Item 7 and elsewhere in this 2023 Annual Report that may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. Our forward-looking statements, financial position and results of operations, are based on our current expectations and beliefs concerning future developments and their potential effects on us. There can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for existing operations and do not include the potential impact of any future acquisitions.

Our forward-looking statements, by their nature, involve significant risks and uncertainties (some of which are beyond our control) and assumptions. They are subject to change based upon various factors including, but not limited to, the risks and uncertainties described in Item 1A of this 2023 Annual Report. Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove to be incorrect, actual results may vary in material respects from those projected in the forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Business Description

The Company is primarily a construction firm that conducts operations through its wholly-owned subsidiaries, GPS, APC, SMC and TRC. GPS and APC represent our power industry services reportable segment that provides a full range of engineering, procurement, construction, commissioning, maintenance, project development and technical consulting services to the power generation market, including the renewable energy sector. The wide range of customers includes independent power project owners, public utilities, power plant heavy equipment suppliers and other commercial firms with significant power requirements. Projects are located in the U.S., Ireland and the U.K. Through TRC, the industrial fabrication and field services reportable segment provides primarily on-site services that support new plant construction and additions, maintenance turnarounds, shutdowns and emergency mobilizations for industrial plants primarily located in the Southeast region of the U.S. and that may include the fabrication, delivery and installation of steel components such as piping systems and pressure vessels. Through SMC Infrastructure Solutions, the telecommunications infrastructure services segment provides project management, construction, installation and maintenance services to commercial, local government and federal government customers primarily in the Mid-Atlantic region of the U.S.

We may make additional opportunistic acquisitions and/or investments by identifying companies with significant potential for profitable growth and realizable synergies with one or more of our existing businesses. However, we may have more than one industrial focus depending on the opportunity and/or needs of our customers. Significant acquired companies will be operated in a manner that we believe will best provide long-term and enduring value for our stockholders.

Overview

Operating Results

Consolidated revenues for Fiscal 2023 were $455.0 million, which represented a decrease of $54.4 million, or 10.7%, from consolidated revenues of $509.4 million reported for Fiscal 2022.

The revenues of the power industry services segment decreased by $52.1 million to $346.0 million for Fiscal 2023 from $398.1 million reported for Fiscal 2022. The revenues of this reportable segment of our business represented 76.0% of consolidated revenues for Fiscal 2023. For Fiscal 2022, the percentage share of consolidated revenues represented by this reportable segment was 78.2%. The industrial fabrication and field services business reported revenues of $92.8 million for Fiscal 2023. This amount represented a decrease of $5.1 million, or 5.2%, from revenues of $97.9 million reported for Fiscal 2022. Revenues provided by this reportable business segment represented 20.4% and 19.2% of corresponding consolidated revenues for Fiscal 2023 and Fiscal 2022, respectively. The telecommunications infrastructure services business increased its revenues to $16.2 million for Fiscal 2023 from revenues of $13.4 million for Fiscal 2022, representing an increase of 20.9%. Revenues provided by this reportable segment represented 3.6% and 2.6% of corresponding consolidated revenues for Fiscal 2023 and Fiscal 2022, respectively.

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Consolidated gross profit declined by $13.4 million, or 13.4%, to $86.4 million for Fiscal 2023, or 19.0% of the corresponding consolidated revenues. The amount of consolidated gross profit reported for Fiscal 2022 was $99.7 million, or 19.6% of the corresponding consolidated revenues. The slight year-over-year decline in gross profit margins reflected primarily the unfavorable impacts of lower gross profit contributions from the power industry services and industrial fabrication and field services segments.

Selling, general and administrative expenses for Fiscal 2023 and Fiscal 2022 were $44.7 million, or 9.8% of corresponding consolidated revenues, and $47.3 million, or 9.3% of corresponding consolidated revenues, respectively. Additionally, due to the unsuccessful project development efforts by our variable interest entity (“VIE”), we recorded an impairment loss related to the capitalized project development costs of the corresponding power plant in the amount of $7.9 million during Fiscal 2022, of which $2.5 million was attributed to the non-controlling interest. During Fiscal 2023, due to the receipt of an unexpected refund payment from PJM related to this project, we reversed approximately $2.0 million of prior year impairment loss, with $1.6 million attributed to the non-controlling interest.

Due primarily to the consolidated pre-tax book income reported for Fiscal 2023 in the amount of $46.0 million, we reported income tax expense in the amount of $11.3 million for the year. For Fiscal 2022, we reported consolidated pre-tax book income of $47.1 million and recorded income tax expense in the amount of $11.4 million.

For Fiscal 2023, our overall operating performance resulted in net income attributable to our stockholders in the amount of $33.1 million, or $2.33 per diluted share. For Fiscal 2022, our overall operating performance resulted in net income attributable to our stockholders in the amount of $38.2 million, or $2.40 per diluted share.

The primary reasons for the reduction in operating results for Fiscal 2023 were the declining revenues associated with the post-peak construction activities of the Guernsey Power Station and the Maple Hill Solar projects; partially offset by increased revenues associated with the Kilroot Power Station and the ESB FlexGen peaker plants.

Project Backlog

At January 31, 2023, our consolidated project backlog amount of $0.8 billion consisted substantially of the projects of the power industry services reporting segment. The comparable backlog amount as of January 31, 2022 was $0.7 billion. Our reported amount of project backlog at a point in time represents the total value of projects awarded to us that we consider to be firm as of that date less the amounts of revenues recognized to date on the corresponding projects.

Typically, we include the total value of EPC services and other major construction contracts in project backlog when we receive a corresponding notice to proceed from the project owner. However, we may include the value of an EPC services contract prior to the receipt of a notice to proceed if we believe that it is probable that the project will commence within a reasonable timeframe, among other factors. Projects that are awarded to us may remain included in our backlog for extended periods of time as customers experience project delays. However, cancellations or reductions may occur that would reduce project backlog and that could adversely affect our expected future revenues.

In October 2022, GPS added the EPC services contract value of the Trumbull Energy Center, a 950 MW natural gas-fired power plant to be built in Lordstown Ohio, to our project backlog as we had a fully executed EPC service contract and we expected contract activities to commence imminently. We received the full notice to proceed with the project from the owner, Clean Energy Future-Trumbull, LLC, in November 2022. We have since commenced activities for the project. This combined cycle power station will consist of two Siemens Energy SGT6-8000H gas fired, high efficiency, combustion turbines with two heat recovery steam generators and a single steam turbine, and contract completion is scheduled for the end of Fiscal 2026.

On the other hand, in May 2019, GPS entered into an EPC services contract to construct a 625 MW power plant in Harrison County, West Virginia. As a limited notice to proceed with certain preliminary activities was received from the owner of this project at the time (a repeat customer), the value of the contract was added to our project backlog. However, meaningful development milestones were not achieved and management concluded that the value of this power plant should be removed from project backlog as of January 31, 2023.

A portion of consolidated project backlog at January 31, 2023 relates to the Guernsey Power Station as GPS completes the commissioning process for this project, the largest single-phase, gas-fired, power plant under construction in the U.S. The substantial completion milestones have been achieved for all three of this plant’s natural gas-fired turbines.

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Final completion of this project is currently expected to occur during the third quarter of Fiscal 2024 after all punch-list items, other commissioning tasks and demobilization efforts have been completed.

We are committed to the construction of state-of-the-art, natural gas-fired power plants, which represents our core business, as important elements of our country’s electricity-generation mix in the future. In addition, we have been directing certain business development efforts to winning projects for the erection of utility-scale wind farms and solar fields and for the construction of hydrogen-based energy and other industrial projects in order to diversify the sources of revenues. We have successfully completed renewable energy projects in the past and we have renewed efforts to obtain new work in other sectors of the power market that will complement our natural gas-fired EPC services projects going forward.

These efforts led to the award of an EPC services contract to us by CPV Maple Hill Solar, LLC, an affiliate of Competitive Power Ventures, Inc., to construct the Maple Hill Solar facility, which we believe will be among the largest solar-powered energy plants in Pennsylvania. Project completion is currently scheduled to occur during the second half of Fiscal 2024. The unique Maple Hill Solar project, which is located in Cambria County, is being constructed using over 235,000 photovoltaic modules to generate approximately 100 MW of electrical power.

Together, the Guernsey Power Station, the Maple Hill Solar facility and the Trumbull Energy Center, represent nearly 3.0 gigawatts of potential electrical power and require the significant engagement of the technical, project support and project management teams of GPS while they team with APC on a new project in Ireland and assist APC with certain other current projects and business development efforts.

The business development efforts conducted by our APC operations have resulted in a significant increase in the project backlog of this business, which amounted to approximately $154 million as of January 31, 2023. A significant award occurred in October 2021 as APC entered into an engineering and construction services contract with EPUKI London, U.K., to construct a 2 x 330 MW natural gas-fired power plant in Carrickfergus that is near Belfast, Northern Ireland, in a structure that was initially designed to enclose coal-fired units. Our project, referred to as the “Kilroot” project, is being developed by EPNI Energy Limited. Full project activities are underway; the overall completion of this project is expected to occur in the latter half of Fiscal 2024.

In May 2022, APC entered into engineering and construction services contracts with Ireland’s Electricity Supply Board (“ESB”) to construct three 65 MW aero-derivative gas turbine flexible generation power plants in and around the city of Dublin, Ireland. Two of the power plants, the Poolbeg and Ringsend FlexGen Power Plants, will be located on the Poolbeg Peninsula, and the Corduff FlexGen Power Plant will be built in nearby Goddamendy. All three projects cleared the applicable capacity auction earlier this year and are expected to operate intermittently during peak periods of electricity demand and as back-up supply options when renewable electricity generation is limited. A full notice to proceed has been received and project activities were commenced. The completion of each power facility is expected to occur near the end of Fiscal 2024.

Most recently, APC was provided with limited notices to proceed with EPC project activities for an open-cycle gas turbine power facility in central Ireland that will have the capacity to generate approximately 264 MW of temporary emergency electrical power. GPS is teaming with APC in performance of this contract.

The project backlog of TRC has been increased by over 175% since January 31, 2022 to approximately $124 million as of January 31, 2023, reflecting a business development emphasis on the award of larger industrial field service construction projects. The recent emphasis on construction opportunities influenced the strategic decision to consolidate the pipe and vessel fabrication facilities to reduce fixed costs, streamline operations and better support a growing and scalable business model.

It is important to note that the start of new projects is primarily controlled by project owners and that delays may occur that are beyond our control. However, we continue to pursue natural gas-fired power plant, renewable energy plant and industrial construction opportunities in the U.S., Ireland and the U.K. Our vision is to safely contribute to the construction of the energy infrastructure and state-of-the-art industrial facilities that are essential to future economic prosperity in the areas where we operate. We intend to realize this vision with motivated, creative, high-energy and customer-driven teams that are committed to delivering the best possible project results each and every time.

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Market Outlook

The overall growth of our power business has been substantially based on the number of combined cycle gas-fired power plants built by us, as many coal-fired plants have been shut down. In 2010, coal-fired power plants accounted for about 45% of net electricity generation in the U.S. For 2022, coal fueled approximately 20% of net electricity generation. It has been reported that the average age of the active plants in the coal-fired fleet approximates 45 years old with an average life span of 50 years; the last coal-fired power plant built in the U.S. was constructed in 2015. On the other hand, natural-gas fired power plants provided approximately 39% of the electricity generated by utility-scale power plants in the U.S. in 2022, representing an increase of 69% from the amount of electrical power generated by natural gas-fired power plants in 2010, which provided approximately 24% of net electricity generation for 2010. The average age of utility-scale natural gas-fired power plants in the U.S. is approximately 22 years old with an average life span of 30 years.

Major advances in the safe combination of horizontal drilling techniques and hydraulic fracturing led to the boom in natural gas supplies which have been available generally at consistently low and stable prices. However, reductions in production levels during the pandemic and an increase in the amount of liquid natural gas exports, among other factors including the Russian invasion of Ukraine, strained domestic natural gas supplies and forced prices upwards. As a result, the price of natural gas in the U.S. increased meaningfully during the 2022 calendar year. However, significant spot price declines are forecast to occur during 2023 before rising again in calendar year 2024. When sudden power needs emerge and natural gas prices are relatively high, power producers often choose to increase coal-fired power to satisfy the short term demands for electricity.

In the reference case of its Annual Energy Outlook 2023, the Energy Information Administration (“EIA”) projects that economic growth paired with increasing electrification in end-user sectors will result in the stable growth of electricity demand in the U.S. through 2050. Declining capital costs for solar panels, wind turbines and battery storage, as well as government subsidies like those included in the Inflation Reduction Act (the “IRA”) will result in renewables becoming increasingly cost effective compared with the alternatives when the costs of building new power capacity are considered. Renewables are increasingly meeting power demand through 2050 as they outcompete natural gas, coal and nuclear power. Uncertainty in natural gas prices leads to different unfavorable projections for combined cycle units in the short term, but in the long term, natural gas demand from the electric power sector stabilizes. As a result of the renewables growth, U.S. coal-fired generation capacity will decline sharply to about 54% of current levels by 2030, with a gradual decline thereafter.

The historic decline in the use of coal as a power source in the U.S. was caused, to a significant extent, by the plentiful supply of domestic and generally inexpensive natural gas which made it the fuel of choice for power plant developers over this period. The pace of the historic increase in the preference for natural gas as an electricity generating fuel source also was energized, in part, by environmental activism and restrictive regulations targeting coal-fired power plants. Now, the environmentalist opposition against coal-fired power generation has expanded meaningfully to target all fossil fuel energy projects, including both power plants and pipelines, and has evolved into powerful support for renewable energy sources.

Protests against fossil-fuel related energy projects garner media attention and stir public skepticism about new projects which have resulted in delays due to onsite protest demonstrations, indecision by local officials and lawsuits. Various cities, counties and states have adopted clean energy and carbon-free goals or objectives with achievement expected by a certain future date, typically 10 to 30 years out. These aspirational goals may increase the risk of a new power plant becoming a stranded asset long before the end of its otherwise useful economic life, which is a risk that potential equity capital providers may be unwilling to take. The difficulty in obtaining project equity financing and the other factors identified above, may be adversely impacting the planning and initial phases for the construction of new natural gas-fired power plants. Lenders, who have become more wary of funding oil-related ventures as environmental, social and governance ideals influence investment decisions, may be generally unwilling to provide capital for energy projects to increase the domestic production and transmission of oil and natural gas. In addition, a recent announcement by Chubb Insurance may signal new difficulties for certain oil and gas projects. In particular, the insurance underwriter will require oil and gas industry clients to implement plans to reduce methane emissions, that are among the most severe greenhouse gases, and will not provide insurance coverage for oil and gas projects in government-protected conservation areas that do not allow for sustainable use.

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We believe that significant uncertainty relates to the policies of the current U.S. Presidential administration. President Biden proposes to make the electricity production in the U.S. carbon free by 2035 and to put the country on the path to achieve net zero carbon emissions by 2050. These policy stances continued during the invasion of Ukraine and the concurrent rise in oil prices as the administration made appeals to other countries to increase oil production while domestic production is challenged by supply chain and labor issues and the maintenance of restrictive regulations. Meanwhile, delays continue for the construction of pipelines needed to transport natural gas to liquid natural gas export facilities for shipment to Western Europe.

In August 2022, President Biden signed the IRA, a climate and healthcare bill that imposes new taxes on corporations with net profits for financial reporting in excess of $1.0 billion, spends billions over a decade on new workers and technology at the Internal Revenue Service (the “IRS”), and funds hundreds of billions in tax subsidies intended to combat climate change among other measures. According to certain commentary, the legislation will cause investment in technologies needed for leaner production and use of fuel types, including hydrogen, nuclear, renewables and fossil fuels. However, it appears that receipt of the tax subsidies will be conditioned on the extent that taxpayers “buy American” and/or pay prevailing wages, among other requirements. Existing supply chains may lack the capacity to meet the demand that the incentives are intended to create. Therefore, the subsidies may not provide the intended economic incentives to renewable and other energy project owners. It is not clear that the legislation, for which the rules and regulations have not yet been finalized, will provide assistance to current and future project owners of fossil-fuel power projects as intended.

Regarding emissions, it is important to note that in its 2023 reference case, EIA projects that U.S. energy-related carbon dioxide emissions will decline by a little over 30% below the 2005 emissions level by 2030. We believe that a significant portion of the reduction related to the shift from coal-fired to natural gas-fired power generation that has already occurred as described above. It appears that from 2005 to 2022, the energy-related emissions declined by approximately 20%. The EIA credits the impacts of the IRA, updates to technology costs and performance across the energy system and changes in the macroeconomic outlook with maintaining the reduction percentage versus the 2005 level of emissions at approximately 30% through 2050. In addition, the EIA indicates that further emissions reductions are limited by longer-term growth in U.S. transportation and industrial activity. The EIA in its report does not include emissions from the power industry among the reasons for the lack of further emission reductions from 2030 through 2050.

The net amount of electricity generation in the U.S. provided by utility-scale wind and solar photovoltaic facilities continues to rise. Together, such power facilities provided approximately 12%, 13% and 15% of the net amount of electricity generated by utility-scale power facilities in 2020, 2021 and 2022, respectively. EIA projects that new wind and photovoltaic solar capacity will continue to be added to the utility-scale power fleet in the U.S. at a brisk pace substantially attributable to declines in the amount of renewable power plant component and power storage costs, an increase in the scale of energy storage capacity (i.e., battery farms and other energy storage technologies), the availability of valuable tax credits and the overall political commitment to renewable energy.

Most of our recently completed and awarded EPC service contracts relate to the construction of natural gas-fired power plants located within the Mid-Atlantic geographic footprint of PJM, which as indicated above operates a capacity market to ensure long-term grid reliability by securing the appropriate amount of power supply resources needed to meet predicted future energy demands. Capacity payments represent meaningful portions of the revenue streams of qualifying power plants.  The capacity auction for a particular delivery year was usually held during the month of May, three years prior to the actual delivery year. However, the 2023/2024 auction, scheduled for December 2021, was postponed until January 2022 and then was postponed again until June 2022. The auction results included increased capacity powered by nuclear, solar and natural gas energy sources, and decreased capacity provided by coal and wind energy sources. However, prices for the 2023/2024 and 2024/2025 delivery years were significantly lower than each previous auction. Capacity auction prices are scheduled to be posted for 2025-2026 in June 2023. However, PJM recently informed stakeholders that it will seek to delay this auction, which would require the approval of the Federal Energy Regulatory Commission, so that market design rule changes proposed by stakeholders might be implemented for all future auctions.

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Uncertainty in this market, including the difficulties experienced by PJM in perfecting a capacity auction design that all of its stakeholders consider to be fair, the repeated capacity auction delays, and the shrinking annual capacity auction prices, may discourage potential power plant owners from commencing the development of new power plants in this area thereby reducing potential new business opportunities for us.

In February 2023, PJM released a position paper that supported the growing concern that the reliability of power grids is being eroded by the rush to renewable power. While acknowledging the reality of the power transition in the PJM system, it warned that its research highlighted four trends that present increasing reliability risks during the transition due to a potential timing mismatch between load growth, resource retirements and the pace of new electricity generating plant additions.

The paper indicates that the growth rate of electricity demand in the PJM footprint is likely to increase from electrification (i.e., shifts to electric-powered automobiles, electric appliances, etc.) coupled with the proliferation of high-demand data centers in the region. Coal-fired and old gas-fired power generation facilities are retiring at a rapid pace due to government and private sector policies as well as economics. The risk is that these retirements may outpace the construction of new power-generating facilities as PJM’s interconnection queue includes primarily intermittent and limited-duration renewable energy resources. Given the operating characteristics of these types of facilities, PJM will need multiple megawatts of renewable power and accompanying battery storage to replace a single megawatt of thermal generation.

In summary, throughout the U.S., the risk of electricity shortages is rising as traditional power plants are being retired more quickly than they can be replaced by renewable energy and battery storage. Power grids are feeling the strain as the U.S. makes the historic transition from conventional power plants fueled by coal and natural gas to cleaner forms of energy such as wind and solar power, and aging nuclear plants are slated for retirement. Electric-grid operators are warning that power-generating capacity is struggling to keep up with demand, a gap that could lead to additional rolling blackouts during heat waves or other peak power periods.

In the U.S., local electricity grids are connected to form larger networks and to improve reliability and economic efficiency and are known as Regional Transmission Operators (“RTOs”) and Independent System Operators (“ISOs”). They are members of three main interconnections, the Eastern Interconnection, the Western Interconnection and the Electric Reliability Council of Texas. These interconnectors cover wide swaths of the U.S. Although the three interconnections operate independently of each other and have very limited transfers of power between them, the operation of interconnections is conducted by balancing authorities, which ensures that power supply and demand are balanced to maintain the reliability of applicable power system. All RTOs, including PJM, and ISOs in the U.S. are balancing authorities. Consequently, reliability threats to individual RTOs and ISOs represent threats to entire interconnection organizations.

The challenge is that wind and solar farms do not produce electricity at all times and they need large batteries to store their output for later use. While large battery storage capacity is under development, regional grid operators have warned that the pace may not be fast enough to offset the closures of traditional power plants that can work around the clock.

Accelerating the build-out of renewable energy sources and batteries has become an especially difficult proposition amid supply-chain challenges and inflation. For example, during Fiscal 2023, the highly publicized probe by the U.S. Commerce Department into whether Chinese solar manufacturers were circumventing trade tariffs on solar panels had the effect of halting imports of key components needed to build new solar farms and effectively brought most of the U.S. solar industry to a temporary standstill.

Additionally, solar and wind energy plant developers continue to confront the problems caused by grid congestion, often unsuccessfully. Many of these projects have been canceled because renewable plants need to be sited where the resources are optimal, often in remote locations where the transmission systems are not robust as power is consumed substantially in urban areas. The costs associated with the necessary grid upgrades may be prohibitive.

U.S. offshore wind projects progress inconsistently, facing challenges in the areas of environmental and fishery impacts, grid connection complexities, transmission planning and federal permitting processes. Further, U.S. projects are confronted

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by shipping regulations that may limit the ability of developers to replicate successful European erection models. Proponents of clean energy also face political challenges from constituencies who oppose the impacts to wildlife and the environment that may be caused by clean energy infrastructure projects.

Electricity generation from commercial nuclear power plants in the U.S. began in 1958. At the end of 2021, the U.S. had 93 operating commercial nuclear reactors at 55 nuclear power plants in 28 states. The average age of these nuclear reactors is about 40 years old with most plants authorized to operate for another 20 years. The newest reactor in the fleet entered service in 2016, which was twenty years after the previous one to begin operation. There are two new reactors under construction in the U.S., Vogtle Units 3 and 4. The completion of these two units is many years behind schedule and the units are billions of dollars in excess of their initial estimated cost.

Renewed interest in nuclear power could result in the construction of new nuclear powered, carbon-free, electricity generation stations in the U.S. that would use smaller and more economical nuclear reactors. The deployment of small modular reactors could mean lower construction and electricity costs through the use of simpler power plant designs, standardized components and passive safety measures. Such plants could be built in less time than larger plants, utilize less space and represent a viable choice for reliable power to offset the intermittencies of renewable power sources. The increase by the U.S. in its use of nuclear power for electricity generation could have unfavorable effects on the demand for new natural gas-fired and additional renewable energy facilities in the future.

Nevertheless, we believe that the lower operating costs of natural gas-fired power plants, the higher energy generating efficiencies of modern gas turbines, and the requirements for grid resiliency should sustain the demand for modern combined cycle and simple cycle gas-fired power plants in the future. Natural gas is relatively clean burning, generally cost-effective, reliable and abundant. New gas-fired power plants incorporate major advances in gas-fired turbine technologies that have provided increased power plant efficiencies while providing the quick starting capabilities and the reliability that are necessary to balance the inherent intermittencies of wind and solar power plants.

We believe that the benefits of natural gas as a source of power are compelling, especially as a complement to the deployment of wind and solar powered energy sources, and that the future long-term prospects for natural gas-fired power plant construction remain generally favorable as natural gas continues to be the primary source for power generation in our country. The future availability of less carbon-intense and higher efficiency natural gas in the U.S. should be a significant factor in the economic assessment of future power generation capacity additions, although the pace of new opportunities emerging may be restrained and the starts of awarded EPC projects may be delayed or cancelled due to the challenges described above.

We also believe that it is also important to note that the plans for certain natural gas-fired power plant projects include the integration of hydrogen-burning capabilities. While the plants will initially burn natural gas alone, it is planned by the respective project owners that the plants will eventually burn a mixture of natural gas and green hydrogen, thereby establishing power-generation flexibility for these plants. We believe this is a winning combination that provides inexpensive and efficient power, enhances grid reliability and addresses clean-air concerns. The building of state-of-the-art power plants with flex-fuel capability replaces coal-fired power plants in the short term with relatively clean gas-fired electricity generation. Further, such additions to the power generation fleet provide the potential for the plants to burn 100% green hydrogen gas, which would provide both base load power and long duration backup power, when the sun is not shining or the wind is not blowing, for extended periods of time and without certain harmful air emissions.

It has been stated that the current scramble for electricity, regardless of source, caused by the Russian invasion of Ukraine has clarified that the 100% transition to renewable energy is in the distant future and has prompted, in part, renewed interest in not only carbon capture techniques, but carbon removal technologies as well. Carbon capture processes grab carbon from smokestacks and other sources of dense greenhouse gases, thereby reducing harmful emissions. Carbon-removal technologies are more demanding as they remove carbon out of the more diffuse open air in order to store it for centuries. Governments, including the U.S., are taking initial steps to boost this industry. The success of this industry could reduce the climate-change fear associated with natural gas-fired power plants.

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The business footprint for TRC encompasses the southeast region of the U.S. where there are many business-friendly local and state governments that welcome industrial production facilities. It is notable that significant events like the COVID-19 pandemic and the commitment to renewable energy in the U.S. are resulting in meaningful new business opportunities for TRC in its region. The national focus on infrastructure improvements, biotechnology advancements and energy storage have resulted in firms that are focused on these trends recently choosing TRC to participate in major construction projects in the region.

The foregoing discussion in this “Market Outlook” does focus on the state of the domestic power market as the EPC services business of GPS provides the predominant amount of our revenues. However, overseas power markets provide important new power construction opportunities for us especially across Ireland and the U.K.

While both of these countries are committed to the increase in energy consumption sourced from wind and the sun on the pathway to net zero emissions, there is a recognition that these sources of electrical power are inherently variable. Other technologies will be required to support these power sources and to provide electricity when power demands exceed the amount of electricity supplied by these renewables. The existence of the necessary power reserve will require conventional generation sources, typically natural gas-fired power plants. APC was awarded the significant Kilroot project late in Fiscal 2022 to build a clean burning natural gas-fired power plant in Northern Ireland so that existing coal-fired power sources there can be replaced.

The U.K. usually holds auctions for power capacity about four years in advance of the delivery date and another auction for a smaller amount of capacity around a year before delivery. Evidence of the power production realities in the U.K. are reflected in the results for Britain’s auction to ensure enough electricity capacity for 2022/2023 that were released in 2022. Capacity cleared at a record high price unlike the results for the most recent PJM capacity auctions. A total of nearly 5 gigawatts of capacity was procured in this auction, with nearly 70% of the power associated with gas-fired plants.

Last year, the Irish government issued a policy statement on the security of the electricity supply in Ireland which confirms the requirement for the development of new support technologies to deliver on its commitment to have 80% of the country’s electricity generated from renewables by 2030. The report emphasizes that this will require a combination of conventional generation (typically powered by natural gas), interconnection to other jurisdictions, demand flexibility and other technologies such as battery storage and generation from renewable gases. The Irish government has approved that the development of new conventional generation (including gas-fired and gasoil distillate-fired generation) is a national priority and should be permitted and supported in order to ensure the security of electricity supply while supporting the growth of renewable electricity generation.

As noted above, APC entered into engineering and construction services contracts during Fiscal 2023 with the ESB to construct three 65 MW aero-derivative gas turbine flexible generation power plants around the city of Dublin, Ireland. All three projects are expected to operate intermittently during peak periods of electricity demand and as back-up supply options when renewable electricity generation is limited. A full notice to proceed was received and project activities were commenced.

Further, the Irish government has recognized that the successful development of data centers in the country is a key aspect in promoting Ireland as a digital economy hot-spot in Europe. The stewards of the electricity supply in Ireland recognize that the large increase in electricity demand presented by the growth of the data center industry represents an evolving, significant risk to the security of the supply. Accordingly, guidelines have been published with the intent to protect both electricity consumers and the security of supply while continuing to allow data centers to connect to the electricity system. Assessment criteria for applications of data centers to obtain grid connections include, among other items, the ability of data center applicants to bring onsite dispatchable power generation (and/or storage) equivalent to or greater than their demand in order to support the security of supply. It is expected that any dispatchable on-site generation that uses fossil fuel sources developed by data center operators will use natural gas as the fuel source. APC recently completed a project to install natural gas-fired power generation for a major data center in the Dublin area.

APC is actively pursuing other new business opportunities in both the renewable and support sectors with its existing and new clients. The governments of Ireland and the U.K. have already made funds available to develop and support specific

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projects. The engineering and construction teams of APC are engaged in continuous discussions with particular stakeholders in certain of these other projects and APC’s management believes that it will be part of their eventual execution.

Over the past few years, GPS has provided top management guidance and project management expertise to APC as it completed its subcontract efforts for a biomass-burning power plant and won the awards of the projects to build new gas-fired power plant units near Belfast and Dublin. APC has provided project management manpower to GPS on several of its EPC services contracts. These recent experiences have demonstrated that the two companies can combine resources effectively. We believe that GPS and APC working together is a competitive advantage as we pursue emerging new business opportunities in Ireland and the U.K., based on the strength of the reputation of GPS for successfully completing large gas-fired power plant projects in the U.S. and the growing recognition in the power community in Ireland and the U.K. that APC is positioned and has the capability to build larger and more complex power projects. Most recently, APC was provided with limited notices to proceed with EPC contract activities for an open-cycle gas turbine power facility to be built in central Ireland that will have the capacity to generate approximately 264 MW of temporary emergency electrical power. GPS is teaming with APC in the performance of this contract.

We are committed to the rational pursuit of new construction projects, including those with overseas locations and unique deployments of power-generation turbines, and the future growth of our revenues. This may result in additional decisions to make investments in the development and/or ownership of new projects. Because we believe in the strength of our balance sheet, we are willing to consider certain opportunities that include reasonable and manageable risks in order to assure the award of the related engineering, procurement, construction or equipment installation services contracts to us.

The competitive landscape for our core EPC services business related to natural gas-fired power plants in the U.S. remains dynamic, although there are fewer competitors for new gas-fired power plant EPC services project opportunities. Several major competitors have exited the market for a variety of reasons or have been acquired. Others have announced intentions to avoid entering into fixed-price contracts. Nonetheless, the competition for new utility-scale gas-fired power plant construction opportunities is fierce and still includes multiple global firms.  We believe that the Company has a reputation as an accomplished, dependable and cost-effective provider of EPC and other large project construction contracting services. With the proven ability to deliver completed power facilities, particularly combined cycle, natural gas-fired power plants, we are focused on expanding our position in the power markets of the U.S., Ireland and the U.K. where we expect investments to be made based on forecasts of electricity demand covering decades into the future. We believe that our expectations are valid and that our plans for the future continue to be based on reasonable assumptions.

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Comparison of the Results of Operations for the Years Ended January 31, 2023 and 2022

We reported net income attributable to our stockholders of $33.1 million, or $2.33 per diluted share, for Fiscal 2023. For the prior year, we reported net income attributable to our stockholders of $38.2 million, or $2.40 per diluted share. The following schedule compares our operating results for Fiscal 2023 and Fiscal 2022 (dollars in thousands):

NM – Not meaningful.

Revenues

Power Industry Services

The revenues of the power industry services business decreased by 13.1%, or $52.1 million, to $346.0 million for Fiscal 2023 compared with revenues of $398.1 million for Fiscal 2022. The revenues of this business represented approximately 76.0% of consolidated revenues for Fiscal 2023 and 78.2% of consolidated revenues for the prior year. The primary reasons for the decline in revenues by this reportable segment for Fiscal 2023 were decreased revenues associated with the post peak construction activities of the Guernsey Power Station and the Maple Hill Solar energy facility, partially offset by increased revenues associated with the construction of the Kilroot Power Station, the ESB FlexGen Peaker plants and the Trumbull Energy Center. Due to the decrease in construction activities during Fiscal 2023, the combined revenues associated with the Guernsey Power Station and the Maple Hill Solar energy facility represented 45.3% of consolidated revenues for Fiscal 2023 compared to 66.7% of consolidated revenues in the prior year during peak construction activity phases. The project backlog amount for the power industry services reportable segment as of January 31, 2023 and 2022 was $0.7 billion.

Industrial Fabrication and Field Services

The revenues of industrial fabrication and field services decreased by $5.1 million, or 5.2%, to $92.8 million for Fiscal 2023 compared with revenues of $97.9 million for Fiscal 2022. The revenues of this business represented approximately 20.4% of consolidated revenues for Fiscal 2023 and 19.2% of consolidated revenues for the prior year. Although revenues declined slightly during the current year, project backlog increased by $79.0 million to $123.5 million as of January 31, 2023 as a result of business development efforts that have been effective at winning project awards from new customers and increasing the size of awards.

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Telecommunications Infrastructure Services

The revenues of telecommunications infrastructure services were $16.2 million for Fiscal 2023 compared with revenues of $13.4 million for Fiscal 2022. The increase in revenues from the prior year primarily related to new revenues provided by the customers of LTI, which was acquired in December 2021.

Cost of Revenues

Due primarily to the decrease in consolidated revenues for Fiscal 2023 compared with revenues for Fiscal 2022, consolidated cost of revenues also decreased. These costs were $368.7 million and $409.6 million for Fiscal 2023 and Fiscal 2022, respectively.

For Fiscal 2023, we reported a consolidated gross profit of approximately $86.4 million, which represented a gross profit percentage of approximately 19.0% of corresponding consolidated revenues. The gross profit for the period reflected primarily the profit contributions of efficient construction activities related to the major projects of the power industry services reporting segment. The gross profit percentages of corresponding revenues for the power industry services, industrial fabrication and field services and telecommunications infrastructure services segments for Fiscal 2023 were 19.8%, 15.9% and 18.4%, respectively.

For Fiscal 2022, we reported a consolidated gross profit of approximately $99.7 million, which represented a gross profit percentage of approximately 19.6% of corresponding consolidated revenues. The gross profit percentages of corresponding revenues for the power industry services, industrial fabrication and field services and the telecommunications infrastructure segments for Fiscal 2022 were 20.3%, 16.9% and 17.0% respectively.

Selling, General and Administrative Expenses

These costs were $44.7 million and $47.3 million for Fiscal 2023 and Fiscal 2022, respectively, representing 9.8% and 9.3% of consolidated revenues for the corresponding periods, respectively. The 5.6% decrease in these expenses between years was primarily due to decreased cash incentive expenses and a gain of $1.6 million, which was attributed to the non-controlling interest and related to the VIE settling on amounts owed for certain previously impaired development costs. See Note 3 to the accompanying consolidated financial statements. Partially offsetting these decreases were the impact of inflationary pressures on our expenses. The costs for Fiscal 2022 also included the provision for credit losses in the amount of $2.4 million; the amount of the provision for credit losses for Fiscal 2023 was insignificant.

Impairment Loss

During Fiscal 2022, we recorded an impairment loss related to the capitalized project development costs of the Chickahominy Power Station project in the amount of $7.9 million, of which $2.5 million was attributed to the non-controlling interest. We did not record any goodwill or other intangible asset impairment losses during Fiscal 2023 or Fiscal 2022.

Other Income, Net

For Fiscal 2023 and Fiscal 2022, the net amounts of other income were $4.3 million and $2.6 million, respectively, which represented an increase of 69.7% between the comparable periods. For Fiscal 2023 and Fiscal 2022, this line item included income in the amounts of $3.0 million and $0.2 million, respectively, earned on funds maintained in money market accounts and interest income earned on CDs, as interest rates have increased meaningfully between periods. For Fiscal 2023 and Fiscal 2022, the weighted average annual interest rates of the CDs and the money market funds during the corresponding years were 1.5% and 0.1%, respectively.

During Fiscal 2023 and Fiscal 2022, APC recorded research and development awards from the U.K. government related to certain qualifying works performed in the total amounts of approximately $0.7 million and $1.7 million, respectively. In addition, during Fiscal 2022, APC received a cash payment for COVID-19 relief from the Irish government in the amount of approximately $1.1 million.

This line item also includes our share of the net income reported a solar fund investment in the amount of $1.1 million for Fiscal 2023; this amount for Fiscal 2022 was a net loss of $0.4 million. See Note 13 to the accompanying financial statements.

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Income Tax Expense

We recorded income tax expense for Fiscal 2023 in the net amount of approximately $11.3 million primarily due to our reporting pre-tax income for financial reporting purposes in the amount of $46.0 million for the year. Our annual effective income tax rate for Fiscal 2023 was 24.6%. This tax rate differed from the statutory federal tax rate of 21% due primarily to the effects of state income taxes and nondeductible executive compensation, and the unfavorable effects of our settlement with the IRS related to research and development credits at an amount lower than we had previously recorded; partially offset by the favorable recognition of tax benefits related to research and development tax credits recognized in the current year and the partial reversal of a valuation allowance of deferred tax assets related to prior year NOLs of APC’s subsidiary in the U.K. See Note 13 to the accompanying consolidated financial statements.

For Fiscal 2022, we recorded income tax expense of approximately $11.4 million primarily due to our reporting pre-tax income for financial reporting purposes in the amount of $47.1 million for the year. Our annual effective income tax rate for Fiscal 2022 was 24.1%. This tax rate differed from the statutory federal tax rate of 21% due primarily to the effects of state income taxes and nondeductible executive compensation.

Net Income (Loss) Attributable to Non-Controlling Interest

As discussed above, due to the gain of $1.6 million related to the VIE settling on amounts owed for certain previously impaired development costs during Fiscal 2023 and the $2.5 million of impairment loss that was attributed to the non-controlling interest in the prior year, net income attributable to the non-controlling interest increased by $4.1 million between fiscal years. See Note 3 to the accompanying consolidated financial statements.

Liquidity and Capital Resources as of January 31, 2023

At January 31, 2023 and 2022, our balances of cash and cash equivalents were $173.9 million and $350.5 million, respectively, which represented a decrease of $176.6 million between years.

The net amount of cash used in operating activities for Fiscal 2023 was $30.1 million. However, our net income for Fiscal 2023, adjusted favorably by the net amount of non-cash income and expense items, represented a source of cash in the total amount of $39.0 million. The increases in accounts receivable, contract assets and other assets in the amounts of $23.2 million, $19.9 million and $3.3 million, respectively, represented uses of cash during the year. Additionally, the reduction in the balance of contract liabilities in the amount of $31.6 million represented a use of cash during the year to fund, on a net basis, the satisfaction of performance obligations on certain of our contracts. These unfavorable balance sheet account changes primarily related to the decline in the construction activity of the Guernsey Power Station project, partially offset by increases in contract liabilities related to the Trumbull Energy Center and several APC projects. The increase in the combined level of accounts payable and accrued expenses in the amount of $9.1 million, represented a source of cash for the year.

Non-operating activities during Fiscal 2023 used cash to increase the level of our short-term investments, which consist entirely of CDs issued by the Bank, by $59.8 million and to make capital expenditures in the amount of $3.4 million. We also used $82.8 million cash in financing activities during Fiscal 2023, including $68.2 million used to repurchase shares of common stock pursuant to our Share Repurchase Plan (see Item 5 in Part II of this Annual Report), and $14.0 million used for the payment of regular cash dividends. As of January 31, 2023, there were no restrictions with respect to intercompany payments between GPS, TRC, APC, SMC and the holding company.

During Fiscal 2022, our balance of cash and cash equivalents declined by a net amount of $16.2 million.

The net amount of cash provided by operating activities for Fiscal 2022 was $28.4 million. Our net income for Fiscal 2022, adjusted favorably by the net amount of non-cash income and expense items, represented a source of cash in the total amount of $57.3 million. The sources of cash from operations for Fiscal 2022 also included a decrease in the balance of contract assets of $21.7 million, primarily due to the settlement of a legal matter by GPS (see Note 11 of the accompanying consolidated financial statements). Reductions in the balances of contract liabilities and accounts payables and accrued expenses, in the amounts of $44.2 million and $5.7 million, respectively, represented uses of cash during Fiscal 2022.

Non-operating activities used cash during Fiscal 2022, including $20.4 million used to repurchase shares of our common stock pursuant to our share repurchase program. Additionally, we used cash in the amount of $15.7 million for the payment of regular cash dividends. Our investment in solar energy projects used cash in the amount of $5.0 million and capital

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expenditures totaled $1.4 million during Fiscal 2022. Partially offsetting these uses of cash, we received cash proceeds related to the exercise of stock options during Fiscal 2022 in the amount of $1.4 million.

At January 31, 2023, a portion of our balance of cash and cash equivalents was invested in government and money market funds with most of their total assets invested in cash, U.S. Treasury obligations and repurchase agreements secured by U.S. Treasury obligations. The major portion of our domestic operating bank account balances are maintained with the Bank. We do maintain certain Euro-based bank accounts in Ireland and certain pound sterling-based bank accounts in the U.K. in support of the operations of APC. We do not believe that the combined amount of the CDs and the cash deposited with the Bank and cash balances maintained at financial institutions in Ireland and the U.K., in excess of government-insured levels, represent material risks.

In order to monitor the actual and necessary levels of liquidity for our business, we focus on net liquidity, or working capital, in addition to our cash balances. Our net liquidity decreased by $48.1 million to $236.2 million as of January 31, 2023 from $284.3 million as of January 31, 2022, due primarily to common stock repurchases and cash dividends, partially offset by net income. As we have no debt service, our fixed asset acquisitions in a reporting period are typically low, and net liquidity includes our short-term investments, our levels of working capital are not subjected to the volatility that affects our levels of cash and cash equivalents.

The term of our Amended and Restated Replacement Credit Agreement with the Bank, as amended in April 2021, was scheduled to expire on May 31, 2024 (the “Credit Agreement”) and included the following features, among others: a lending commitment of $50.0 million including a revolving loan with interest at the 30-day LIBOR plus 1.6% (reduced from 2.0%), and an accordion feature which allows for an additional commitment amount of $10.0 million, subject to certain conditions. On March 6, 2023, we entered into the Second Amendment (the “Second Amendment”) to the Credit Agreement, which modifies the Credit Amendment to, among other things, replace the interest pricing from the 30-day LIBOR plus 1.6% to the Secured Overnight Financing Rate (“SOFR”) plus 1.6% and adds SOFR successor rate language. The Credit Agreement, as newly amended, continues to include customary terms, covenants and events of default for a credit facility of its size and nature.

We may also use the borrowing ability to cover other credit instruments issued by the Bank for our use in the ordinary course of business as defined by the Bank. At January 31, 2023, we had no outstanding borrowings, however the Bank has issued letters of credit in the total outstanding amount of $8.8 million in support of the activities of APC under new customer contracts.

We have pledged the majority of our assets to secure the financing arrangements. The Bank’s consent is not required for acquisitions, divestitures, cash dividends or significant investments as long as certain conditions are met. The Credit Agreement, as amended, requires that we comply with certain financial covenants at our fiscal year-end and at each fiscal quarter-end, and includes other terms, covenants and events of default that are customary for a credit facility of its size and nature, including a requirement to achieve positive adjusted earnings before interest, taxes, depreciation and amortization, as defined, over each rolling twelve-month measurement period. At January 31, 2023, we were compliant with the covenants of the Credit Agreement, as amended.

In the normal course of business and for certain major projects, we may be required to obtain surety or performance bonding, to provide parent company guarantees, or to cause the issuance of letters of credit (or some combination thereof) in order to provide performance assurances to clients on behalf of one of our subsidiaries.

If our services under a guaranteed project would not be completed or would be determined to have resulted in a material defect or other material deficiency, then we could be responsible for monetary damages or other legal remedies. As is typically required by any surety bond, we would be obligated to reimburse the issuer of any surety bond issued on behalf of a subsidiary for any cash payments made thereunder. The commitments under performance bonds generally end concurrently with the expiration of the related contractual obligation. Not all of our projects require bonding.

As of January 31, 2023 and 2022, the estimated amounts of the Company’s unsatisfied bonded performance obligations, covering all of its subsidiaries, were approximately $0.6 billion and $0.2 billion, respectively. In addition, as of January 31, 2023 and 2022, the outstanding amounts of bonds covering other risks, including warranty obligations related to completed activities, were not material. Not all of our projects require bonding.

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We have also provided a financial guarantee in the amount of $3.6 million to support certain project developmental efforts. A liability was established for the estimated loss related to this guarantee during Fiscal 2022.

When sufficient information about claims related to performance on projects would be available and monetary damages or other costs or losses would be determined to be probable, we would record such losses. As our subsidiaries are wholly-owned, any actual liability related to contract performance is ordinarily reflected in the financial statement account balances determined pursuant to the Company’s accounting for contracts with customers. Any amounts that we may be required to pay in excess of the estimated costs to complete contracts in progress as of January 31, 2023 are not estimable.

Returns on money market instruments and certificates of deposit were limited for some time due to market conditions. With the desire to increase the amount of return on its available cash, the Company made prior year investments of approximately $6.3 million in limited liability companies that make equity investments in solar energy projects that are eligible to receive energy tax credits. It is likely that we will evaluate opportunities to make other solar energy investments of this type in the future.

We believe that cash on hand, our cash equivalents, cash that will be provided from the maturities of short-term investments and cash generated from our future operations, with or without funds available under our Credit Agreement, as amended, will be adequate to meet our general business needs in the foreseeable future. In general, we maintain significant liquid capital in our consolidated balance sheet to ensure the maintenance of our bonding capacity and to provide parent company performance guarantees for EPC and other construction projects.

However, any significant future acquisition, investment or other unplanned cost or cash requirement, may require us to raise additional funds through the issuance of debt and/or equity securities. There can be no assurance that such financing will be available on terms acceptable to us, or at all.

Contractual Obligations

During Fiscal 2023, there was no significant change in the nature or amounts of our contractual obligations. We estimate that the balance of such contractual obligations as of January 31, 2023 was less than $10 million. The two largest items in this estimate, operating leases and deferred compensation, are amounts included as liabilities in our consolidated balance sheet. The remainder of such obligations relate primarily to open service arrangements. Outstanding commitments represented by open purchase orders and subcontracts related to our construction contracts have not been included in the estimated amounts of contractual obligations as such amounts are expected to be funded through contract billings to customers. We do not have any significant obligations for materials or subcontracted services beyond those required to complete construction contracts awarded to us.

Special Purpose Entities

As is common in our industry, EPC contractors and third parties form joint ventures, limited partnerships and limited liability companies for purposes of executing a project or program for a project owner. These teaming arrangements are typically dissolved upon completion of the project or program.

In addition, we may obtain interests in VIEs formed by its owners for a specific purpose. The evaluation of whether such interests represent our financial control of a VIE requires analysis and judgement. In January 2018, we concluded that we were the primary beneficiary of a VIE formed by an independent firm for the purpose of developing a natural gas-fired power plant in Virginia. As a result, the VIE was included in our consolidated financial statements until the fourth quarter of Fiscal 2023, when we determined that we were no longer the primary beneficiary and we deconsolidated the entity. During Fiscal 2022, as described in Note 3 to the accompanying consolidated financial statements, we recorded an impairment loss related to the development costs associated with the project in the amount of $7.9 million, of which $2.5 million was attributed to the non-controlling interest. Prior to deconsolidation, however, the VIE settled on amounts owed for certain impaired development costs and recognized a gain of $1.6 million, all of which was attributed to the non-controlling interest.

We have entered into similar support arrangements with other independent parties in the past that resulted in the successful development and our construction of three separate gas-fired power plant projects. We were paid project development fees for each project and our loans to the development entities were repaid in full plus interest. In each of these cases, we deconsolidated the corresponding VIE when we were no longer the primary beneficiary.

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We may enter into other support arrangements in the future in connection with power plant development opportunities when they arise and when we are confident that providing early financial support for the projects will lead to the award of the corresponding EPC contracts to us.

Earnings before Interest, Taxes, Depreciation and Amortization (“EBITDA”)

We believe that EBITDA is a meaningful presentation that enables us to assess and compare our operating performance on a consistent basis by removing from our operating results the impacts of our capital structure, the effects of the accounting methods used to compute depreciation and amortization and the effects of operating in different income tax jurisdictions. Further, we believe that EBITDA is widely used by investors and analysts as a measure of performance.

However, as EBITDA is not a measure of performance calculated in accordance with U.S. GAAP, we do not believe that this measure should be considered in isolation from, or as a substitute for, the results of our operations presented in accordance with US GAAP that are included in our consolidated financial statements. In addition, our EBITDA does not necessarily represent funds available for discretionary use and is not necessarily a measure of our ability to fund our cash needs.

The following table presents the determinations of EBITDA for Fiscal 2023 and Fiscal 2022, respectively (amounts in thousands).

Critical Accounting Policies and Estimates

We consider the accounting policies discussed below related to revenue recognition on long-term construction contracts; income tax reporting; and the financial reporting associated with any significant claims or legal matters to be most critical to the understanding of our financial position and results of operations.

Critical accounting policies are those related to the areas where we have made what we consider to be particularly subjective or complex judgments in arriving at estimates and where these estimates can significantly impact our financial results under different assumptions and conditions.

These estimates, judgments, and assumptions affect the reported amounts of assets, liabilities and equity, the disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets, liabilities and equity that are not readily apparent from other sources. Actual results and outcomes could differ from these estimates and assumptions. We do periodically review these critical accounting policies and estimates with the audit committee of our board of directors.

Revenue Recognition

Our revenues are primarily derived from construction contracts that can span several quarters or years. We enter into EPC and other long-term construction contracts principally on the basis of competitive bids or in conjunction with our support of the development of power plant projects. The types of contracts may vary. However, the EPC contracts of our power industry services reporting segment, and most other large contracts awarded to our other companies, are fixed-price contracts. Revenues are recognized primarily over time as performance obligations are satisfied due to the continuous transfer of control to the project owner or other customer. The accuracy of our revenues and profit recognition in a given period depends on the accuracy of our estimates of the forecasted contract value, or transaction price, and the cost to complete the work for each project.

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Central to accounting for revenues from contracts with customers is a five-step revenue recognition model that requires reporting entities to:

The guidance focuses on the transfer of the control of the goods and/or services to the customer, as opposed to the transfer of risk and rewards. Major provisions cover the determination of which goods and services are distinct and represent separate performance obligations, the appropriate treatment of variable consideration, and the evaluation of whether revenues should be recognized at a point in time or over time. In general, application of the rules requires us to make important judgements and meaningful estimates that may have significant impact on the amounts of revenues recognized by us for any reporting period.

Revenues from fixed price contracts, including a portion of estimated profit, are recognized over time, based on costs incurred and estimated total contract costs using the percentage-of-completion method. The cost and profit estimates are re-forecasted monthly for all significant contracts pursuant to a detailed “bottoms-up” determination and review process. The results of the process are subjected to reviews by senior management with the applicable project management personnel at each subsidiary. The intensity of the reviews may vary between projects depending on the percentage-of-completion for the projects, among other factors. The percentage-of-completion method measures the ratio of costs incurred and accrued to date for each contract to the estimated, or forecasted, total cost for each contract at completion. This requires us to prepare on-going estimates of the forecasted cost to complete each contract as the project progresses. In preparing these estimates, we make significant judgments and assumptions about our significant costs, including materials, labor and equipment, and we evaluate contingencies based on possible schedule variances, major equipment delivery delays, construction delays, weather or other productivity factors.

Actual costs may vary from the costs we estimate. Variations from estimated contract costs, along with other risks inherent in fixed-price contracts, may result in actual revenues and gross profits differing from those we estimate and could result in losses on projects or other significant unfavorable impacts on our operating results for any fiscal quarter or year. If a current estimate of total contract cost indicates a loss on a contract, the projected loss is recognized in full when determined, without regard to the percentage of completion. There are a number of factors that can contribute to changes in estimated contract costs, revenues and profitability. The most significant of these are identified in the first item included in the Risks Related to our Operational Execution section of Part I, Item 1A. of this Annual Report entitled Risk Factors.

Crucial to the compliance with the accounting standard covering the recognition of revenues on contracts with customers is the identification of the promises made to the customer by us that are included in the contract. If a promise is distinct, as that concept is defined in the accounting standard, it represents a separate performance obligation. Contracts may have multiple promises. The amounts of revenue associated with each promise are recognized when, or as, the performance obligations are satisfied. However, complex contracts may include only one performance obligation if the multiple promises are not distinct within the context of the contract. For example, if the promises that could be considered distinct are interrelated or require us to perform integration so that the customer receives a complete product, the contract is considered to include only one performance obligation. Most of our long-term contracts have a single performance obligation as the promises to transfer individual goods or services are not separately identifiable from other promises within the context of the contract. Our EPC contracts require us to deliver a complete and functioning power plant, not just functioning components.

The transaction price of a contract represents the value used to determine the amount of revenues recognized as of the balance sheet date. It may reflect amounts of variable consideration, which could be either increases or decreases to the transaction price. These adjustments can be made from time-to-time during the period of contract performance as circumstances evolve related to such items as variations in the scope and price of contracts, claims, incentives and liquidated damages.

The Company may include an estimated amount of variable consideration in the transaction price to the extent it is probable that a significant reversal of cumulative revenues recognized on the particular contract will not occur when the uncertainty

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associated with the variable consideration is resolved. The Company’s determination of the amount of variable consideration to be included in the transaction price of a particular contract is based largely on an assessment of the Company’s anticipated performance and all information (historical, current and forecasted) that is reasonably available. The effect of any revisions to the transaction price on the amount of previously recognized revenues that is due to the addition or reduction of variable consideration is recorded currently as an adjustment to revenues on a cumulative catch-up basis. In the event that any amounts of variable consideration that are reflected in the transaction price of a contract are not resolved in the Company’s favor, there could be reductions in, or reversals of, previously recognized revenues. In most significant instances, modifications to our contracts do not represent the addition of new performance obligations.

Contract results may be impacted by estimates of the amounts of contract variations that we expect to receive. The effects of any resulting revisions to revenues and estimated costs can be determined at any time and they could be material. As of January 31, 2023 and 2022, the aggregate amounts of contract variations reflected in estimated transaction prices were $11.6 million and $7.5 million, respectively.

Substantially all of our customer contracts include the right for customers to terminate contracts for convenience as disclosed in Note 4 to the consolidated financial statements. Current accounting guidance indicates that the value of future work that companies are contractually obligated to perform pursuant to active customer contracts should not be included in the disclosure of remaining unsatisfied performance obligations when the corresponding contracts include termination for convenience clauses without substantial penalties accruing to the customers upon such terminations. In the application of this guidance, we assess whether the nature of the work being performed under contract is largely service-based and repetitive and should be considered a succession of one-month contracts for the duration of the identified term of the contract. Predominantly, our customers contract with us to construct assets, to fabricate materials or to perform emergency maintenance or outage services where we believe a substantial penalty or cost would be incurred upon a termination for convenience. We believe that in substantially all cases, there would be substantial costs incurred by a customer if it terminated a contract with us for convenience including the costs of terminating subcontracts, canceling purchase orders and returning or otherwise disposing of delivered materials and equipment. Further, to the best of management’s knowledge, the Company has never had a customer terminate a contract with us for convenience. Therefore, our disclosure in Note 4 of the value of remaining unsatisfied performance obligations on active customer contracts represents an amount based on contracts or orders received from customers that the Company believes are firm and where the parties are acting in accordance with their respective obligations.

Our long-term contracts typically have schedule dates and other performance obligations that, if not achieved, could subject us to liquidated damages. These contract requirements generally relate to specified activities that must be completed by an established date or by achievement of a specified level of output or efficiency. Each contract defines the conditions under which a project owner may make a claim for liquidated damages. The amounts of liquidated damages owed to a project owner pursuant to the terms of a contract would represent reductions of the transaction price of the corresponding contract.

At the outset of each of the Company’s contracts, the potential amounts of liquidated damages typically are not subtracted, from the transaction price as the Company believes that it has included activities in its contract plan, and has reflected the associated costs in its forecasts of completed contract costs, that will be effective in preventing such damages. Of course, circumstances may change as the Company executes the corresponding contract. The transaction price is reduced by an applicable amount when the Company no longer considers it probable that a future reversal of revenues will not occur when the matter is resolved. In general, we consider potential liquidated damages, the costs of other related items and potential mitigating factors in determining the estimates of forecasted revenues and the adequacy of our estimates of the cost to complete contracts.

Uncertain Income Tax Positions

As we have disclosed in the “Research and Development Tax Credits” section of Note 13 to the accompanying consolidated financial statements, during Fiscal 2019, we completed a detailed review of the activities of our engineering staff on major EPC services projects in order to identify and quantify the amounts of research and development credits available to reduce prior year income taxes. This extensive study focused on the costs incurred on specific projects during the three-year period ended January 31, 2018. Based on the results of the study, we identified and estimated significant amounts of income tax benefits that were not previously recognized in our financial results for any prior year reporting period.

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Under current professional accounting guidance, income tax positions must meet a more-likely-than-not recognition threshold to be recognized. Income tax positions that previously failed to meet the more-likely-than-not threshold are recognized in the first subsequent financial reporting period in which that threshold is met. Fiscal 2019 was the initial reporting period in which we had sufficient data on which to make an evaluation and to reach a conclusion on the amount of income tax credit benefits related to prior year project costs that, more likely than not, qualified as research and development costs under the Internal Revenue Code and the rules and regulations of certain states. The net amount of the credits that we recognized in income taxes during Fiscal 2019 was $16.2 million, as subsequently reduced by $0.4 million. Based on our judgement, the amount of income tax benefits related to identified research and development income tax credits that we assessed as not meeting the threshold criteria for recognition was $5.0 million. Most of this liability was included in accrued expenses as of January 31, 2022.

The research and development credits were included in amendments to our consolidated federal income tax returns for Fiscal 2016 and Fiscal 2017, that were filed in January 2019, and our consolidated federal income tax return for Fiscal 2018, that was filed in November 2018. In January 2021, the IRS issued its final revenue agents reports that disagreed with our treatment of a substantial amount of the costs that supported our claims. In March 2021, we submitted a formal protest of the findings of the IRS examiner and requested an appeal hearing.

At the conclusion of the hearing that occurred in May 2022, we agreed to accept a settlement offer from the IRS in the amount of approximately $7.9 million, before interest, which was approximately 42% of the total of our claims. As a result, during the three-month period ended July 31, 2022, we made an unfavorable adjustment to income tax expense for Fiscal 2023 in the amount of $6.2 million.

In a manner similar to the process described above, we completed a detailed review of the activities of our engineering staff on major EPC services projects in order to identify and quantify the amounts of research and development tax credits that may have been available to reduce federal income taxes for Fiscal 2022 and Fiscal 2021. As a result, we filed amended federal income tax returns for those years, including research and development tax credits in the total amount of $5.8 million. Based on our judgment, the amount of income tax benefits related to these identified research and development income tax credits that we assessed as not meeting the threshold criteria for accounting recognition was approximately $2.4 million. Subsequent to January 31, 2023, we obtained an insurance policy covering our tax position in the event that we would suffer a loss related to our research and development claims.

Deferred Tax Assets and Liabilities

Our consolidated balance sheet as of January 31, 2023 includes net deferred tax assets in the amount of approximately $3.7 million. The components of our deferred taxes are presented in Note 13 to the accompanying consolidated financial statements. These amounts reflect differences in the periods in which certain transactions are recognized for financial and income tax reporting purposes.

We consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized on a jurisdiction-by-jurisdiction basis. Our ability to realize our deferred tax assets, including those related to the past NOLs incurred in the U.K. (that applicable income tax rules will allow us to use in order to offset future amounts of applicable taxable income), depends primarily upon the generation of sufficient future taxable income to allow for the realization of our deductible temporary differences. If such estimates and assumptions regarding income amounts change in the future, we may be required to record additional valuation allowances against some or all of the deferred tax assets resulting in additional income tax expense in our consolidated statement of earnings. During Fiscal 2020, a valuation allowance in the amount of $7.1 million was established against the deferred tax asset amount created by the NOL of APC’s subsidiary in the U.K. (“APC UK”) for Fiscal 2020. During Fiscal 2023, APC UK continued a turnaround of its operating results such that we believe it has a stable earnings history upon which APC UK can reliably forecast future profitable operations. Based on the forecast that rests on the belief that meaningful investments will be made in the power infrastructure of the U.K. for the foreseeable future, we now believe it is more likely than not that a certain portion of the deferred tax asset will be realized. Accordingly, we reversed a portion of the corresponding allowance during Fiscal 2023 in the amount of $2.6 million.

A deferred tax asset in the amount of $8.3 million was recorded as of January 31, 2020 associated with the income tax benefit of our domestic NOL for Fiscal 2020 without any corresponding valuation allowance. Among other changes, the CARES Act re-established a carryback period for certain losses to five years. The NOLs eligible for carryback under the CARES Act include our domestic loss for Fiscal 2020, which was approximately $39.5 million. The carryback provided

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a favorable rate benefit for us as the loss, which was incurred in a year where the statutory federal tax rate was 21%, has been carried back to tax years where the tax rate was higher. The net amount of this additional income tax benefit, which we recorded in Fiscal 2021, was $4.4 million. We have made the appropriate filing with the IRS requesting carryback refunds of income taxes paid in prior years. With the enactment of the CARES Act, the asset amount, which totals $12.7 million, was moved to income taxes receivable representing a complete utilization of the NOL within one year of its occurrence. The IRS has not completed the processing of our refund request.

At this time, we believe that the historically strong earnings performance of our power industry services segment will provide sufficient income during the years when most of our other deferred tax assets become deductible in the U.S. in order for us to realize the applicable temporary income tax differences. Accordingly, we believe that it is more likely than not that we will realize the benefit of significantly all of our net deferred tax assets.

Legal Contingencies

We do become involved in legal matters where litigation has been initiated or claims have been made against us. At this time, we do not believe that any material loss is probable related to any current matters. We do maintain accrued expense balances for the estimated amounts of legal costs expected to be billed related to any significant matter. We review the status of each matter and assess the adequacy of the accrued expense balances at the end of each fiscal quarter, and make adjustments to the balances if necessary. Should our assessments of the outcomes of outstanding legal matters change, significant losses or additional costs may be recorded.

During Fiscal 2022, the significant legal matter described below, for which we had been providing regular disclosure in our filings, was settled.

In January 2019, GPS filed a lawsuit against Exelon West Medway II, LLC and Exelon Generation Company, LLC (together referred to as “Exelon”) for Exelon’s breach of contract and failure to remedy various conditions which negatively impacted the schedule and the costs associated with the construction by GPS of a gas-fired power plant for Exelon in Massachusetts. Subsequently, Exelon provided GPS with a notice intending to terminate the EPC contract under which GPS had been providing services to Exelon and served us with contractual notice requiring GPS to vacate the construction site. At that time, the construction project was nearly complete and both of the power generation units included in the plant had successfully reached first fire. The completion of various prescribed performance tests and the clearance of punch-list items were the primary tasks necessary to be accomplished by GPS in order to achieve substantial completion of the power plant. Exelon asserted that GPS failed to fulfill certain obligations under the contract and was in default, withholding payments from GPS on invoices rendered to Exelon in accordance with the terms of the contract between the parties.

Our firm belief that Exelon received the benefits of the construction efforts of GPS and the corresponding progress made on the project without making payments to GPS for the value received was reflected in our accounting for the project that we maintained throughout the duration of the dispute. There were outstanding invoices billed to Exelon and unbilled costs incurred on the project, with substantial balances included in both accounts receivable and contract assets as of January 31, 2021. The final settlement of all outstanding claims between the parties resulting in Exelon making a payment to GPS in the amount of $27.5 million, which amount was in excess of the total carrying amount of the related accounts receivable and contract assets. The excess amount was included in revenues for Fiscal 2022.

Recently Issued Accounting Pronouncements

There are no other recently issued accounting pronouncements that have not yet been adopted that we consider material to our consolidated financial statements.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion summarizes the financial position of Argan, Inc. and its subsidiaries as of January 31, 2022, and the results of their operations for Fiscal 2022 and Fiscal 2021, and should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in Item 8 of this 2022 Annual Report.

Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in the Company’s Annual Report on Form 10-K for the year ended January 31, 2021, that was filed with the SEC on April 14, 2021, for a discussion of financial trends, variance drivers and other significant matters for Fiscal 2021 as compared to Fiscal 2020.

Cautionary Statement Regarding Forward Looking Statements

The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for certain forward-looking statements. We have made statements in this Item 2 and elsewhere in this 2022 Annual Report that may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. Our forward-looking statements, including those relating to the potential effects of the COVID-19 pandemic on our business, financial position and results of operations, are based on our current expectations and beliefs concerning future developments and their potential effects on us. There can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for existing operations and do not include the potential impact of any future acquisitions.

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Our forward-looking statements, by their nature, involve significant risks and uncertainties (some of which are beyond our control) and assumptions. They are subject to change based upon various factors including, but not limited to, the risks and uncertainties described in Item 1A of this 2022 Annual Report. Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove to be incorrect, actual results may vary in material respects from those projected in the forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Business Description

Argan is a holding company that conducts operations through its wholly-owned subsidiaries, GPS, APC, SMC and TRC. Through GPS and APC, we provide a full range of engineering, procurement, construction, commissioning, operations management, maintenance, development, technical and consulting services to the power generation market, including the renewable energy sector, for a wide range of customers, including independent power project owners, public utilities, equipment suppliers and global energy plant construction firms. GPS and APC represent our power industry services reportable segment. Through TRC, the industrial fabrication and field services reportable segment provides on-site services that support maintenance turnarounds, shutdowns and emergency mobilizations for industrial plants primarily located in the southeast region of the U.S. and that are based on its expertise in producing, delivering and installing fabricated steel components such as piping systems and pressure vessels. Through SMC Infrastructure Solutions, the telecommunications infrastructure services segment provides project management, construction, installation and maintenance services to commercial, local government and federal government customers primarily in the Mid-Atlantic region of the U.S.

We intend to make additional opportunistic acquisitions and/or investments by identifying companies with significant potential for profitable growth and realizable synergies with one or more of our existing businesses. However, we may have more than one industrial focus depending on the opportunity. We expect that acquired companies will be maintained in separate subsidiaries that will be operated in a manner that best provides cash flows for the Company and value for our stockholders.

Overview

Operating Results

Consolidated revenues for Fiscal 2022 were $509.4 million, which represented an increase of $117.1 million, or 29.9%, from consolidated revenues of $392.2 million reported for Fiscal 2021.

The revenues of the power industry services segment increased by $78.7 million to $398.1 million for Fiscal 2022 from $319.4 million reported for Fiscal 2021. The revenues of this reportable segment of our business represented 78.2% of consolidated revenues for Fiscal 2022. For Fiscal 2021, the percentage share of consolidated revenues represented by this reportable segment was 81.4%. The industrial services business of TRC reported revenues of $97.9 million for Fiscal 2022. This amount represented an increase of $32.6 million, or 49.9%, from revenues of $65.3 million reported by TRC for Fiscal 2021. Revenues provided by this reportable business segment represented 19.2% and 16.6% of corresponding consolidated revenues for Fiscal 2022 and Fiscal 2021, respectively. The telecommunications infrastructure services business increased its revenues to $13.4 million for Fiscal 2022 from revenues of $7.6 million for Fiscal 2021, representing an increase of 76.4%. Revenues provided by this reportable segment represented 2.6% and 1.9% of corresponding consolidated revenues for Fiscal 2022 and Fiscal 2021, respectively.

Consolidated gross profit improved by $37.6 million, or 60.5%, to $99.7 million for Fiscal 2022, or 19.6% of the corresponding consolidated revenues. The amount of consolidated gross profit reported for Fiscal 2021 was $62.1 million, or 15.8% of the corresponding consolidated revenues. The year-over-year improvement reflected primarily the favorable impacts of the higher consolidated revenues and favorable gross profit contributions from all three reportable business segments.

Selling, general and administrative expenses for Fiscal 2022 and Fiscal 2021 were $47.3 million, or 9.3% of corresponding consolidated revenues, and $39.0 million, or 10.0% of corresponding consolidated revenues, respectively. Additionally, due to the unsuccessful project development efforts by our VIE, we recorded an impairment loss related to the capitalized project development costs of this project in the amount of $7.9 million during Fiscal 2022, of which $2.5 million was attributed to the non-controlling interest.

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Due primarily to the consolidated pre-tax book income reported for Fiscal 2022 in the amount of $47.1 million, we reported income tax expense in the amount of $11.4 million for the year. For Fiscal 2021, we reported consolidated pre-tax book income of $24.9 million and recorded income tax expense in the amount of $1.1 million, which amount is net of a $4.4 million net operating loss (“NOL”) carryback benefit.

For Fiscal 2022, our improved overall operating performance resulted in net income attributable to our stockholders in the amount of $38.2 million, or $2.40 per diluted share. For Fiscal 2021, we reported net income attributable to our stockholders in the amount of $23.9 million, or $1.51 per diluted share.

The primary drivers of our improved operating performance for Fiscal 2022 were the increased revenues and steady gross margin contribution associated with the construction of the Guernsey Power Station, the new revenues and gross profit contributions of the solar facility EPC services project at Maple Hill, and the strong results of TRC and APC which both reported increased revenues and gross profit amounts for Fiscal 2022.

Engineering, Procurement and Construction Service Contracts

At January 31, 2022, our consolidated project backlog amount of $0.7 billion consisted substantially of the projects of the power industry services reporting segment. The comparable backlog amount as of January 31, 2021 was $0.8 billion. Our reported amount of project backlog at a point in time represents the total value of projects awarded to us that we consider to be firm as of that date less the amounts of revenues recognized to date on the corresponding projects (project backlog is larger than the value of remaining unsatisfied performance obligations, or RUPO, on active contracts; see Note 4 to the accompanying consolidated financial statements).

Typically, we include the total value of EPC services and other major construction contracts in project backlog when we receive a corresponding notice to proceed from the project owner. However, we may include the value of an EPC services contract prior to the receipt of a notice to proceed if we believe that it is probable that the project will commence within a reasonable timeframe, among other factors. Projects that are awarded to us may remain included in our backlog for extended periods of time as customers experience project delays. However, cancellations or reductions may occur that would reduce project backlog and that could adversely affect our expected future revenues.

A meaningful amount of the project backlog amount at January 31, 2022 was represented by the Guernsey Power Station, the largest single-phase, gas-fired, power plant construction project in the U.S. Substantial completion of this project is currently scheduled to occur during the second half of Fiscal 2023.

Despite our commitment to the construction of state-of-the-art, natural gas-fired power plants as important elements of our country’s electricity-generation mix in the future, we have been directing certain business development efforts to winning projects for the erection of utility-scale wind farms and solar fields and for the construction of hydrogen-based and other renewable energy projects. We have successfully completed these types of projects in the past and we have renewed efforts to obtain new work in the renewable power sector that will complement our natural gas-fired EPC services projects going forward. These efforts led to our announcement in May 2021 that GPS entered into an EPC services contract with CPV Maple Hill Solar, LLC, an affiliate of CPV, to construct the Maple Hill Solar facility, which we believe will be among the largest solar-powered energy plants in Pennsylvania. Project activities were begun by GPS immediately. Project completion is currently scheduled to occur during the second half of Fiscal 2023. The unique Maple Hill Solar project, which is located in Cambria County, will be constructed using over 235,000 photovoltaic modules to generate approximately 100 MW of electrical power.

The business development efforts conducted by our APC operations have resulted in a significant increase in the project backlog of this business. The most significant award occurred in October 2021 as APC entered into an engineering and construction services contract with EPUKI London, UK, to construct a 2 x 330 MW natural gas-fired power plant in Carrickfergus that is near Belfast, Northern Ireland, and that will replace coal-fired units at the site. The facility is being developed by EPNI Energy Limited. A notice to proceed was received and project activities have commenced. The overall completion of this project is expected to occur in the latter half of Fiscal 2024.

For Fiscal 2022, meaningful amounts of revenues and gross profit were contributed by the U.K. operations of APC that have completed the installation of a synchronized condenser for the combined cycle, gas-fired, power plant located at the Isle of Grain site in the Kent region of the U.K.

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The U.K. operating unit of APC also completed its subcontracted construction efforts consisting primarily of the mechanical installation of the boiler for TeesREP. With a power rating of 299 MW, TeesREP is one of the largest bio-mass-fueled power stations in the world that will burn primarily wood pellets in order to generate electricity sufficient to power 600,000 homes.

The management of APC also grew its Irish operations during Fiscal 2022. For example, APC is performing the design and build of a dedicated power plant within a major data center. The size and configuration of the facility, consisting of up to nine (9) gas-fired turbines, is a first-of-a-kind facility within the Irish data center market. They are also completing construction activities for a major computer chip manufacturer. Both of these Irish projects are located near Dublin.

As announced in Fiscal 2019, GPS entered into an EPC services contract to construct the Chickahominy Power Station, a 1,740 MW natural gas-fired power plant, in Charles City County, Virginia. We did not include the value of this contract in our project backlog. We provided financing through notes receivable from the consolidated VIE that was established by the project owner and that was dedicated to the development efforts. We also provided technical support to the project. Significant development milestones were achieved by the project owner. However, a planned gas pipeline expansion that the project owner believed would supply natural gas to the power plant was rejected by Virginia’s State Corporation Commission during Fiscal 2022, which led to cancellation by PJM of its interconnection service agreement with the project based on alleged failures of the project to meet required milestones. In February 2022, PJM received notice from FERC accepting PJM’s termination of the service agreement which effectively removed the Chickahominy Power Station from PJM’s planning queue.

In summary, the project owner was unable to secure an alternative fuel-supply for the plant and the project lost its interconnection service commitment with PJM. Therefore, the project owner was unable to obtain the necessary equity financing for the project and we ceased providing project development funding. We concluded that the completion of the development of this project is significantly jeopardized and that it is doubtful that construction of this power plant will occur. Accordingly, consistent with the disclosure included in the Current Report on Form 8-K that we filed on January 24, 2022, we recorded an impairment loss during the fourth quarter of Fiscal 2022 related to the capitalized project development costs of this project in the amount of $7.9 million, of which $2.5 million was attributed to the non-controlling interest. In March 2022, the project owner issued a public statement that the project was cancelled.

Market Outlook

The overall growth of our power business has been substantially based on the number of combined cycle gas-fired power plants built by us, as many coal-fired plants have been shut down. In 2010, coal-fired power plants accounted for about 45% of total electricity generation. For 2021, coal accounted for approximately 22% of net electricity generation. On the other hand, natural-gas fired power plants provided approximately 38% of the electricity generated by utility-scale power plants in the U.S. in 2021, representing an increase of 60% from the amount of electrical power generated by natural gas-fired power plants in 2010, which provided approximately 24% of net electricity generation for 2010. Undoubtedly, the long-term historic decline in the use of coal as a power source in the U.S. was caused, to a significant extent, by the plentiful supply of domestic and generally inexpensive natural gas which made it the fuel of choice for power plant developers over this period.

In the reference case of its Annual Energy Outlook 2022, the EIA projects average increases to utility-scale electricity generation in the U.S. of slightly less than 1% per year from 2022 through 2050. The shift from coal to natural gas as a power plant energy source in the U.S. is expected to continue as the EIA projects that coal-fired generation will decline by 45% from 2022 through 2050, and will represent only 11% of the net electricity generation mix by the end of this period. The net electricity generation from natural gas-fired power plants is projected to increase by 17% in the U.S. by 2050.

The pace of the historic increase in the preference for natural gas as an electricity generating fuel source was energized, in part, by environmental activism and restrictive regulations targeting coal-fired power plants. Now, the environmentalist opposition against coal-fired power generation has expanded meaningfully to target all fossil fuel energy projects, including power plants and pipelines, and has evolved into powerful support for renewable energy sources.

Protests against fossil-fuel related energy projects continue to garner media attention and stir public skepticism about new projects resulting in delays due to onsite protest demonstrations, indecision by local officials and lawsuits. During Fiscal 2021, a natural gas-fired power plant that we had been awarded the EPC services contract to build, the Brooke County Power project, was canceled by its developer. Although changing market conditions were cited as important factors in the

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cancellation decision and despite strong local support for the project, the opposition by the governor of West Virginia was likely a factor in the declining enthusiasm for the project. Further, during Fiscal 2021, Dominion Energy and Duke Energy announced the abandonment of plans to complete the major Atlantic Coast Pipeline, ending a seven-year effort to build a 600-mile natural gas pipeline between West Virginia and eastern North Carolina, citing that the economic viability of the project was threatened by continuing delays and increasing cost uncertainty after a federal judge issued a ruling preventing the use of an accelerated construction permitting process. Most recently, as disclosed above, the developer cancelled the Chickahominy power station project, citing opposition from outside interests and onerous regulations largely advanced by the renewable energy movement.

In the New England and Mid-Atlantic regions of the U.S., power plant operators are challenged by the requirements of the Regional Greenhouse Gas Initiative, or “RGGI,” which is a cooperative effort by states in these regions to cap and reduce power sector carbon dioxide emissions. In addition, various cities, counties and states have adopted clean energy and carbon-free goals or objectives with achievement expected by a certain future date, typically 10 to 30 years out. These aspirational goals may increase the risk of a new power plant becoming a stranded asset long before the end of its otherwise useful economic life, which is a risk that potential equity capital providers may be unwilling to take. The difficulty in obtaining project equity financing and the other factors identified above, may be adversely impacting the planning and initial phases for the construction of new natural gas-fired power plants.

Perhaps the most significant uncertainty relates to the policies of the current U.S. Presidential administration. President Biden proposes to make the electricity production in the U.S. carbon free by 2035 and to put the country on the path to achieve net zero carbon emissions by 2050. As soon as he was elected, Mr. Biden caused the U.S. to re-join the Paris Climate Agreement and he cancelled the permit allowing the Keystone XL Pipeline to cross the border from Canada into the U.S. In addition, Mr. Biden ordered a pause on the U.S. government entering into new oil and natural gas leases on public lands or offshore waters to the extent possible, the launch of a rigorous review of all existing leasing and permitting practices related to fossil fuel development on public lands and waters, and the identification of steps that can be taken to double renewable energy production from offshore wind by 2030. These policy stances have continued during the war in the Ukraine and the current surge in oil prices as the administration makes appeals to other countries to increase oil production.

Accordingly, the net amount of electricity generation in the U.S. provided by utility-scale wind and solar photovoltaic facilities continues to rise. Over the last two years, the net generation has increased by almost 35%. Together, such power facilities provided approximately 9%, 11% and 12% of the net amount of electricity generated by utility-scale power facilities in 2019, 2020 and 2021, respectively. In EIA’s 2022 reference case, net electricity generation from all renewable power sources is expected to increase by more than 161% and represent over 42% of such generation by 2050. Impetus for this growth is provided by both public concerns about climate change and U.S. government subsidies. Environmental activism has resulted in the passage of laws and the establishment of regulations that discourage new fossil-fuel burning power plants and provide income tax advantages that promote the growth of wind and solar power. Declines in the amount of renewable power plant component and power storage costs and an increase in the scale of energy storage capacity (i.e., battery farms) have also occurred.

Over the next few years, EIA projects that new wind and photovoltaic solar capacity will continue to be added to the utility-scale power fleet in the U.S. at a brisk pace substantially attributable to declining equipment costs and the availability of valuable tax credits. As these credits decline and then expire early in the next decade as currently scheduled, the wind capacity additions are expected to slow. Although the special tax incentives related to solar power also expire, the continuing decline in the cost of solar power equipment is predicted to sustain the growth of photovoltaic solar power generation facilities.

Nonetheless, we believe that relatively low natural gas prices will persist over the long-term. Together with the lower operating costs of natural gas-fired power plants, the higher energy generating efficiencies of modern gas turbines, and the requirements for grid resiliency should sustain the demand for modern combined cycle and simple cycle gas-fired power plants in the future. Natural gas is relatively clean burning, cost-effective and reliable. We believe that its benefits as a source of power are compelling, especially as a complement to the growing deployment of wind and solar powered energy sources. We continue to believe that the future long-term prospects for natural gas-fired power plant construction remain generally favorable as natural gas continues to be the primary source for power generation in our country.

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New gas-fired power plants incorporate major advances in gas-fired turbine technologies that have provided increased power plant efficiencies while providing the quick starting capabilities and the reliability that are necessary to balance the inherent intermittencies of wind and solar power plants.

It has been reported that renewables currently provide approximately 36% of electricity generation in California. Yet, the increasing dependence on intermittent renewable energy sources, especially solar, is making it harder to ensure reliable power in California as millions of its residents lost power during a late summer heat wave in 2020. With hopes of preventing future rolling blackouts in California, regulators there approved the acquisition of five emergency natural gas-fueled electricity generators with an aggregate power output of approximately 150 MW. Analysis of the causes of last winter’s widespread power outages in Texas during a frigid stretch of weather is complex. The residents of Texas suffered as the severe cold froze wind turbines and the lack of sun diminished the power contributions of solar powered facilities. However, natural gas-fired power plants in Texas were forced offline as well primarily due to frozen well-site equipment and the decisions by regulators to prioritize natural gas for residential use, which caused interruptions to the supply of natural gas to the plants. However, in both states, the significant amount of renewable power capacity failed to rise to the occasion. A diversity lesson from both power crises may be that fossil-fuel electricity generation sources remain critical elements of the power generation mix in order to assure grid reliability and the avoidance of power outages.

Additionally, solar and wind energy plant developers continue to confront the problems caused by grid congestion, often unsuccessfully. Many of these projects have been canceled because renewable plants need to be sited where the resources are optimal, often in remote locations where the transmission systems are not robust. The costs associated with the necessary grid upgrades may be prohibitive. U.S. offshore wind projects progress inconsistently, facing challenges in the areas of environmental and fishery impacts, grid connection and capability and federal permitting processes. Further, projects are confronted by shipping regulations in the U.S. that may limit the ability of developers to replicate successful European construction and installation models. Proponents of clean energy also face political challenges. Voters in the state of Maine were energized by local residents seeking to preserve pristine woodlands and rejected a project that would transmit hydropower from Canada into New England.

Renewed interest in nuclear power could result in the construction of new nuclear powered, carbon-free, electricity generation stations in the U.S. that would use smaller and more economical nuclear reactors. The deployment of small modular reactors could mean lower construction and electricity costs through the use of simpler power plant designs, standardized components and passive safety measures. Such plants could be built in less time than larger plants, utilize less space and represent a viable choice for reliable power to offset the intermittencies of renewable power sources. The increase by the U.S. in its use of nuclear power for electricity generation could have unfavorable effects on the demand for new natural gas-fired and additional renewable energy facilities in the future.

Major advances in the safe combination of horizontal drilling techniques and hydraulic fracturing led to the boom in natural gas supplies which have been available generally at consistently low prices. The abundant availability of cheap, less carbon-intense and higher efficiency natural gas in the U.S. should continue to be a significant factor in the economic assessment of future power generation capacity additions although the pace of new opportunities emerging may be restrained and the starts of awarded EPC projects may be delayed.

We believe that it is also important to note that the plans for certain natural gas-fired power plant projects include the integration of hydrogen-burning capabilities. While the plants will initially burn natural gas alone, it is planned by the respective project owners that the plants will eventually burn a mixture of natural gas and green hydrogen, thereby establishing power-generation flexibility for these plants. We believe this is a winning combination that provides inexpensive and efficient power, enhances grid reliability and addresses the clean-air concerns of environmentalists. The building of state-of-the-art power plants with flex-fuel capability replaces coal-fired power plants in the short term with relatively clean gas-fired electricity generation. Further, such additions to the power generation fleet provide the potential for the plants to burn 100% green hydrogen gas, which would provide both base load power and long duration backup power, when the sun is not shining and the wind is not blowing, for extended periods of time and without certain harmful air emissions.

The foregoing discussion in our “Market Outlook” does focus on the state of the domestic power market as the EPC services business of GPS provides the predominant amount of our revenues. However, we realize that overseas power markets may provide important new power construction opportunities for us in the future as the management of APC has growing enthusiasm for opportunities in the electricity generation markets across Ireland and the U.K. While both of these

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countries are committed to the increase in energy consumption sourced from wind and the sun on the pathway to net zero emissions, there is a recognition that these sources of electrical power are inherently variable. Other technologies will be required to support these power sources and to provide electricity when power demands exceed the amount of electricity supplied by these renewables. The existence of the necessary power reserve will require conventional generation sources, typically natural gas-fired power plants. APC was awarded a significant contract late in Fiscal 2022 to build a clean burning natural gas-fired power plant in Northern Ireland so that existing coal-fired power sources there can be shut-down.

The U.K. usually holds auctions for power capacity about four years in advance of the delivery date and another auction for a smaller amount of capacity around a year before delivery. Evidence of the shifting power generation priorities in the U.K. are reflected in the results for Britain's auction to ensure enough electricity capacity for 2022/23 that were released in February 2022. Capacity cleared at a record high price. A total of nearly 5 gigawatts of capacity was procured in this auction, with nearly 70% of the power associated with gas-fired plants, a provisional auction document showed.

The Irish government recently issued a policy statement on the security of the electricity supply in Ireland which confirms the requirement for the development of new support technologies to deliver on its commitment to have 80% of the country’s electricity generated from renewables by 2030. The report emphasizes that this will require a combination of conventional generation (typically powered by natural gas), interconnection to other jurisdictions, demand flexibility and other technologies such as energy storage (i.e., batteries) and generation from renewable gases (i.e., biomethane and/or hydrogen produced from renewable sources). The Irish government has approved that the development of new conventional generation (including gas-fired and gasoil distillate-fired generation) is a national priority and should be permitted and supported in order to ensure the security of electricity supply while supporting the growth of renewable electricity generation. Since January 31, 2022, the Irish operations of APC have received limited notices to proceed with early activities related to the construction of two new gas-fired power plant facilities near Dublin.

Further, the Irish government has recognized that the successful development of data centers in the country is a key aspect in promoting Ireland as a digital economy hot-spot in Europe. In the absence of data centers, Ireland would be experiencing much more modest electricity demand growth, consistent with population growth and the general development of industrial demand. However, the stewards of the electricity supply in Ireland recognize that the large increase in electricity demand presented by the growth of the data center industry represents an evolving, significant risk to the security of the supply. Accordingly, guidelines have been published recently with the intent to protect both electricity consumers and the security of supply while continuing to allow data centers to connect to the electricity system. Assessment criteria for applications of data centers to obtain grid connections include, among other items, the ability of data center applicants to bring onsite dispatchable power generation (and/or storage) equivalent to or greater than their demand in order to support the security of supply. It is expected that any dispatchable on-site generation that uses fossil fuel sources developed by data center operators will use natural gas as the fuel source; again, natural gas is considered to be a transitional fuel in Ireland’s efforts to meet its climate action plan targets. As identified above, earlier this year, APC was awarded a project to install natural gas-fired power generation for a major data center in the Dublin area.

In a previous section of this 2022 Annual Report, we identified that there are risks to our businesses, particularly APC, related to the war in Ukraine. However, our APC business may benefit from an increased focus by European Union countries on the import of liquid natural gas as an alternative to piped supplies from Russia. The construction of new conversion facilities, pipelines and power plants could provide new construction opportunities for us.

APC is actively pursuing new business opportunities in both the renewable and support sectors with its existing and new clients. The governments of Ireland and the U.K. have already made funds available to develop and support specific projects. The engineering and construction teams of APC are engaged in continuous discussions with particular stakeholders in certain of these projects and they are confident that APC will be part of their eventual execution.

Over the past few years, GPS has provided top management guidance and project management expertise to APC as it completed its subcontract efforts for the TeesREP power plant and won the award of the project to build the new gas-fired power plant in Northern Ireland. APC has provided project management manpower to GPS on several of its EPC services contracts. These recent experiences have demonstrated that the two companies can combine resources effectively. Considerations of the manner in which GPS and APC can work together in the future are becoming more formal in view of emerging new business opportunities in the U.K. and Ireland, the strength of the reputation of GPS for successfully completing large gas-fired power plant projects in the U.S. and the growing recognition in the power community in the British and Irish islands that APC is committed to and capable of tackling larger and more complex power projects.

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We are committed to the rational pursuit of new construction projects, including those with overseas locations and unique deployments of power-generation turbines, and the future growth of our revenues. This may result in additional decisions to make investments in the development and/or ownership of new projects. Because we believe in the strength of our balance sheet, we are willing to consider certain opportunities that include reasonable and manageable risks in order to assure the award of the related engineering, procurement, construction or equipment installation services contracts to us.

The competitive landscape for our core EPC services business related to natural gas-fired power plants in the U.S. has changed significantly over the last five years. While the domestic market remains dynamic, we are moving into an era where there may be fewer competitors for new gas-fired power plant EPC services project opportunities. Several major competitors have exited the market for a variety of reasons or have been acquired. Others have announced intentions to avoid entering into fixed-price contracts. Nonetheless, the competition for new utility-scale gas-fired power plant construction opportunities is fierce and still includes multiple global firms.

We believe that the Company has a reputation as an accomplished, dependable and cost-effective provider of EPC and other large project construction contracting services. With the proven ability to deliver completed power facilities, particularly combined cycle, natural gas-fired power plants, we are focused on expanding our position in the power markets of the U.S., Ireland and the U.K. where we expect investments to be made based on forecasts of electricity demand covering decades into the future. We believe that our expectations are valid and that our plans for the future continue to be based on reasonable assumptions.

Comparison of the Results of Operations for the Years Ended January 31, 2022 and 2021

We reported net income attributable to our stockholders of $38.2 million, or $2.40 per share, for Fiscal 2022. For the prior year, we reported net income attributable to our stockholders of $23.9 million, or $1.51 per diluted share. The following schedule compares our operating results for Fiscal 2022 and Fiscal 2021 (dollars in thousands).

NM – Not meaningful.

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Revenues

Power Industry Services

The revenues of the power industry services business increased by 24.7%, or $78.7 million, to $398.1 million for Fiscal 2022 compared with revenues of $319.4 million for Fiscal 2021. The revenues of this business represented 78.2% of consolidated revenues for Fiscal 2022 and 81.4% of consolidated revenues for the prior year.

The primary drivers for the strong performance by this reportable segment for Fiscal 2022 were increased revenues associated with the construction of the Guernsey Power Station and the new Maple Hill Solar energy facility, which together represented 66.7% of consolidated revenues. Last year, the revenues of this segment included primarily revenues associated with the construction of the Guernsey Power Station project and the TeesREP project, which together represented 76.1% of consolidated revenues for Fiscal 2021.

Industrial Fabrication and Field Services

The revenues of industrial fabrication and field services (representing the business of TRC) increased by $32.6 million, or 50.0%, to $97.9 million for Fiscal 2022, providing 19.2% of consolidated revenues for Fiscal 2022. Revenues of TRC for Fiscal 2021 represented approximately 16.6% of corresponding consolidated revenues. The improved current year business of TRC reflects increased project activity for several customers, primarily in field services, as they loosened COVID-19 work restrictions.

Telecommunications Infrastructure Services

The revenues of this business segment (representing the business of SMC) were $13.4 million for Fiscal 2022 compared with revenues of $7.6 million for Fiscal 2021, which reflected strong performance by both the inside-premises and outside-premises groups as certain customers in this segment also loosened COVID-19 work restrictions.

Cost of Revenues

Due primarily to the increase in consolidated revenues for Fiscal 2022 compared with revenues for Fiscal 2021, consolidated cost of revenues also increased. These costs were $409.6 million and $330.1 million for Fiscal 2022 and Fiscal 2021, respectively.

For Fiscal 2022, we reported a consolidated gross profit of approximately $99.7 million, which represented a gross profit percentage of approximately 19.6% of corresponding consolidated revenues. The gross profit for the period reflected primarily the profit contributions of efficient construction activities related to the major projects of the power industry services reporting segment, the improved business of the industrial services segment and the revenues associated with the settlement of a legal matter. The gross profit percentages of corresponding revenues for the power industry services, industrial services and the telecommunications infrastructure segments for Fiscal 2022 were 20.3%, 16.9% and 17.0%, respectively.

For Fiscal 2021, we reported a consolidated gross profit of approximately $62.1 million which represented a gross profit percentage of approximately 15.8% of corresponding consolidated revenues. The gross profit percentages of corresponding revenues for the power industry services, industrial services and the telecommunications infrastructure segments for Fiscal 2021 were 16.4%, 12.3% and 22.4%, respectively. We believe that the gross margin percentages for Fiscal 2021 are indicative of the percentages that should be expected for Fiscal 2023.

Selling, General and Administrative Expenses

These costs were $47.3 million and $39.0 million for Fiscal 2022 and Fiscal 2021, respectively, representing 9.3% and 10.0% of consolidated revenues for the corresponding periods, respectively. The 21.2% increase in these expenses between years occurred within each of our reporting segments primarily due to increased personnel and associated costs, including cash incentive and stock compensation expenses, and business development costs. The costs for Fiscal 2022 also included the provision for credit losses in the amount of $2.4 million. The amount of the provision for credit losses for Fiscal 2021 was insignificant.

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Impairment Loss

During the fourth quarter of Fiscal 2022, we recorded an impairment loss related to the capitalized project development costs of the Chickahominy Power Station project in the amount of $7.9 million as discussed above, of which $2.5 million was attributed to the non-controlling interest. We did not record any goodwill or other intangible asset impairment losses during Fiscal 2022.

Other Income

For Fiscal 2022 and Fiscal 2021, the net amounts of other income were $2.6 million and $1.9 million, respectively, which represented an increase of 37.3% between the comparable periods. During Fiscal 2022, APC received research and development grant payments from the government of the U.K. related to certain qualifying works performed during Fiscal 2019 in the total amount of approximately $1.7 million. In addition, APC received COVID-19 relief from the Irish government, which amounted to approximately $1.1 million. This line item also included our share of the net loss reported by the solar fund investment for Fiscal 2022 in the amount of $0.5 million that is discussed in Note 13 to the accompanying consolidated financial statements.

Typically, the amounts reported on this line include primarily income earned on funds maintained in money market accounts and interest income earned on bank certificates of deposit. Adverse economic reactions to the uncertainties of the COVID-19 pandemic commenced during the middle of Fiscal 2021, including sharp reductions in investment interest rates. Other income from earnings on our temporary investments of excess cash for Fiscal 2022 was insignificant although the aggregate amount of invested funds increased between the periods. For Fiscal 2021, the net amount of other income of $1.9 million included primarily earnings on our temporary investments of excess cash before the pandemic.

Income Taxes

We recorded income tax expense for Fiscal 2022 in the net amount of approximately $11.4 million due to our reporting pre-tax income for financial reporting purposes in the amount of $47.1 million for the year. Our annual effective income tax rate for Fiscal 2022 was 24.1%. This tax rate differs from the statutory federal tax rate of 21% due primarily to the effects of state income taxes and nondeductible executive compensation.

For Fiscal 2021, we recorded income tax expense of $1.1 million, which amount was reduced significantly by the NOL carryback benefit in the approximate amount of $4.4 million that is also described in Note 13 to the accompanying consolidated financial statements.

Liquidity and Capital Resources as of January 31, 2022

Our working capital increased by $14.2 million to $284.3 million as of January 31, 2022 from $270.1 million as of January 31, 2021, due primarily to the net income earned during Fiscal 2022 attributable to the stockholders of Argan, offset partially by the effects of cash payments for dividends and share repurchases. However, our balance of cash and cash equivalents declined by a net amount of $16.2 million during Fiscal 2022 as the net change in our operating assets and liabilities represented a use of cash of approximately $28.9 million for the year.

The net amount of cash provided by operating activities for Fiscal 2022 was $28.4 million. Our net income for Fiscal 2022, adjusted favorably by the net amount of non-cash income and expense items, represented a source of cash in the total amount of $57.3 million. The sources of cash from operations for Fiscal 2022 also included a decrease in the balance of contract assets of $21.7 million, primarily due to the settlement of a legal matter by GPS (see Note 11 of the accompanying consolidated financial statements). Reduction in the balances of contract liabilities and accounts payables and accrued expenses, in the amounts of $44.2 million and $5.7 million, respectively, represented uses of cash during Fiscal 2022.

Non-operating activities used cash during Fiscal 2022, including $20.4 million used to repurchase shares of our common stock pursuant to our share repurchase program (see Item 5 in Part II of this Annual Report). Additionally, we used cash in the amount of $15.7 million for the payment of regular cash dividends. Our investment in solar energy projects used cash in the amount of $5.0 million and capital expenditures totaled $1.4 million during Fiscal 2022. Partially offsetting these uses of cash, we received cash proceeds related to the exercise of stock options during Fiscal 2022 in the amount of $1.4 million. As of January 31, 2022, there were no restrictions with respect to inter-company payments between GPS, TRC, APC, SMC and the holding company.

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During Fiscal 2021, our balance of cash and cash equivalents increased by $199.3 million to $366.7 million while our working capital decreased by $7.6 million to $270.1 million as of January 31, 2021 from $277.7 million as of January 31, 2020 due primarily to the amount of regular and special cash dividends paid during the year.

The net amount of cash provided by operating activities for Fiscal 2021 was $176.0 million. Our net income for Fiscal 2021, adjusted favorably by the net amount of non-cash income and expense items, represented a source of cash in the total amount of $41.5 million. The sources of cash from operations for Fiscal 2021 also included a temporary increase in the balance of contract liabilities associated with the early phases of construction activities on projects of GPS and TRC in the amount of $99.4 million. A reduction in the balances of accounts receivable and contract assets, primarily at the TRC and APC operations, provided cash in the amounts of $8.5 million and $6.7 million, respectively. In addition, the combined level of accounts payable and accrued expenses increased by $31.4 million during Fiscal 2021, a source of cash for the year.

Fiscal 2021 also reflected an entry to record the carryback of our NOL incurred for Fiscal 2020 to prior income tax years. The loss carryback should result in a refund of federal income taxes in the amount of $12.7 million. This tax refund receivable was included in the balance of other current assets as of January 31, 2021, which was the primary cause of the net increase in this balance of $11.5 million during Fiscal 2021, which represented a use of cash.

Primary sources of cash for Fiscal 2021 were the net maturities of short-term investments, certificates of deposit issued by the Bank, in the amount of $70.0 million. Non-operating activities used cash during Fiscal 2021, including the payment of regular and special cash dividends in the total amount of $47.0 million. During Fiscal 2021, capital expenditures were reduced by approximately 76.1% to $1.7 million from a capital expenditures amount of $7.1 million for Fiscal 2020. We also used cash in the amount of $1.3 million during Fiscal 2021 to make an investment in a solar energy project. Partially offsetting these uses of cash, we received cash proceeds related to the exercise of stock options during Fiscal 2021 in the amount of $1.6 million.

At January 31, 2022, most of our balance of cash and cash equivalents was invested in government and prime money market funds with most of their total assets invested in cash, U.S. Treasury obligations and repurchase agreements secured by U.S. Treasury obligations. The major portion of our domestic operating bank account balances are maintained with the Bank. We do maintain certain Euro-based bank accounts in the Ireland and certain pound sterling-based bank accounts in the U.K. in support of the operations of APC.

The original term of our Amended and Restated Replacement Credit Agreement with the Bank was scheduled to expire on May 31, 2021. During April 2021, the Company and the Bank agreed to an amendment to the Credit Agreement which extended the expiration date of the Credit Agreement to May 31, 2024 and reduced the borrowing rate. The Credit Agreement, as amended, includes the following features, among others: a lending commitment of $50.0 million including a revolving loan with interest at the 30-day LIBOR plus 1.6% (reduced from 2.0%), and an accordion feature which allows for an additional commitment amount of $10.0 million, subject to certain conditions. We may also use the borrowing ability to cover other credit instruments issued by the Bank for our use in the ordinary course of business as defined by the Bank. At January 31, 2022, we had no outstanding borrowings, however the Bank has issued letters of credit in the total outstanding amount of $21.5 million in support of the activities of APC under new customer contracts. In connection with the project development activities of the VIE, the Bank issued a letter of credit, outside the scope of the Credit Agreement, in the approximate amount of $3.4 million for which we have provided cash collateral. The Company expects to amend the Credit Agreement during Fiscal 2023 in order to replace LIBOR with an equivalent benchmark rate. The Company does not expect that the change will materially impact its consolidated financial statements.

We have pledged the majority of our assets to secure the financing arrangements. The Bank’s consent is not required for acquisitions, divestitures, cash dividends or significant investments as long as certain conditions are met. The Credit Agreement, as amended, requires that we comply with certain financial covenants at our fiscal year-end and at each fiscal quarter-end, and includes other terms, covenants and events of default that are customary for a credit facility of its size and nature, including a requirement to achieve positive adjusted earnings before interest, taxes, depreciation and amortization, as defined, over each rolling twelve-month measurement period. At January 31, 2022 and 2021, we were compliant with the covenants of the Credit Agreement, as amended.

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In the normal course of business and for certain major projects, we may be required to obtain surety or performance bonding, to provide parent company guarantees, or to cause the issuance of letters of credit (or some combination thereof) in order to provide performance assurances to clients on behalf of one of our subsidiaries.

If our services under a guaranteed project would not be completed or would be determined to have resulted in a material defect or other material deficiency, then we could be responsible for monetary damages or other legal remedies. As is typically required by any surety bond, we would be obligated to reimburse the issuer of any surety bond issued on behalf of a subsidiary for any cash payments made thereunder. The commitments under performance bonds generally end concurrently with the expiration of the related contractual obligation. Not all of our projects require bonding.

As of January 31, 2022, the value of the Company’s unsatisfied bonded performance obligations, covering all of its subsidiaries, was approximately $235.1 million. In addition, as of January 31, 2022, there were bonds outstanding in the aggregate amount of approximately $1.0 million covering other risks including warranty obligations related to completed activities; the majority of these bonds expire at various dates during Fiscal 2023.

We have also provided a financial guarantee on behalf of GPS to an original equipment manufacturer in the amount of $3.6 million to support project developmental efforts. During Fiscal 2022, the Company established a liability for an estimated loss related to this guarantee.

When sufficient information about claims related to our performance on projects would be available and monetary damages or other costs or losses would be determined to be probable, we would record such losses. As our subsidiaries are wholly-owned, any actual liability related to contract performance is ordinarily reflected in the financial statement account balances determined pursuant to the Company’s accounting for contracts with customers. Any amounts that we may be required to pay in excess of the estimated costs to complete contracts in progress as of January 31, 2022 are not estimable.

Returns on money market instruments and certificates of deposit are currently minimal due to market conditions. With the desire to increase the amount of return on its available cash, the Company invested approximately $5.0 million during Fiscal 2022, in a limited liability company that makes equity investments in solar energy projects that are eligible to receive energy tax credits (see Note 13 to the accompanying consolidated financial statements). During Fiscal 2021, we made a similar investment in the amount of $1.3 million. The Fiscal 2022 investment is expected to provide an overall return of approximately 20% over the six-year expected life of our investment. It is likely that we will evaluate opportunities to make other solar energy investments of this type in the future.

We believe that cash on hand, our cash equivalents, cash that will be provided from the maturities of short-term investments and cash generated from our future operations, with or without funds available under our Credit Agreement, will be adequate to meet our general business needs in the foreseeable future. In general, we maintain significant liquid capital in our consolidated balance sheet to ensure the maintenance of our bonding capacity and to provide parent company performance guarantees for EPC and other construction projects.

However, any significant future acquisition, investment or other unplanned cost or cash requirement, may require us to raise additional funds through the issuance of debt and/or equity securities. There can be no assurance that such financing will be available on terms acceptable to us, or at all.

Contractual Obligations

During 2022, there was no significant change in the nature or amounts of our contractual obligations. The amount of contract obligations disclosed as of January 31, 2021 was $8.2 million. The two largest items included in this total, operating leases and deferred compensation, are amounts included as liabilities in our consolidated balance sheet. The remainder of the disclosed amount related primarily to open service arrangements. Outstanding commitments represented by open purchase orders and subcontracts related to our construction contracts have not been included in the disclosed amounts as such amounts are expected to be funded through contract billings to customers. We do not have any significant obligations for materials or subcontracted services beyond those required to completed construction contracts awarded to us.

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Special Purpose Entities

As is common in our industry, EPC contractors and third parties form joint ventures, limited partnerships and limited liability companies for purposes of executing a project or program for a project owner. These teaming arrangements are typically dissolved upon completion of the project or program.

In addition, we may obtain interests in VIEs formed by its owners for a specific purpose. The evaluation of whether such interests represent our financial control of a VIE requires analysis and judgement. We concluded that we are the primary beneficiary of a VIE formed by an independent firm for the purpose of developing a natural gas-fired power plant in Virginia. As a result, the VIE is included in our consolidated financial statements until we determine that our financial control of the entity has passed to another party. Pursuant to agreements negotiated with the developer, we lent funds to the VIE to cover certain costs of the project development effort. The development phase activities of the VIE were focused on 1) obtaining the necessary permits to build and operate the power plant, 2) completing arrangements to connect the power plant to the fuel supply and the electricity grid, 3) engaging energy plant operators in negotiations for the purchase of project ownership interests, and 4) securing permanent financing for the project. For consolidated reporting purposes, these costs have been presented as project development costs and included in property, plant and equipment. During Fiscal 2022, as described in Note 3 to the accompanying consolidated financial statements, we recorded an impairment loss related to these costs in the amount of $7.9 million, of which $2.5 million was attributed to the non-controlling interest.

We have entered into similar support arrangements with other independent parties in the past that resulted in the successful development of three separate gas-fired power plant projects where we were paid project development fees in the total amount of $29.6 million, and where our loans in the amount of $11.7 million were repaid in full plus interest in the amount of $2.3 million. In each of these cases, we deconsolidated the corresponding VIE when we were no longer the primary beneficiary.

We may enter into other support arrangements in the future in connection with power plant development opportunities when they arise and when we are confident that providing early financial support for the projects will lead to the award of the corresponding EPC contracts to us.

Earnings before Interest, Taxes, Depreciation and Amortization (“EBITDA”)

We believe that EBITDA is a meaningful presentation that enables us to assess and compare our operating cash flow performance on a consistent basis by removing from our operating results the impacts of our capital structure, the effects of the accounting methods used to compute depreciation and amortization and the effects of operating in different income tax jurisdictions. Further, we believe that EBITDA is widely used by investors and analysts as a measure of performance. However, as EBITDA is not a measure of performance calculated in accordance with U.S. GAAP, we do not believe that this measure should be considered in isolation from, or as a substitute for, the results of our operations presented in accordance with US GAAP that are included in our consolidated financial statements. In addition, our EBITDA does not necessarily represent funds available for discretionary use and is not necessarily a measure of our ability to fund our cash needs.

The following table presents the determinations of EBITDA for Fiscal 2022 and Fiscal 2021, respectively (amounts in thousands).

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As we believe that our net cash flow provided by or used in operations is the most directly comparable performance measure determined in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”), the following table reconciles the amounts of EBITDA for the applicable years, as presented above, to the corresponding amounts of net cash flows provided by operating activities that are presented in our consolidated statements of cash flows for Fiscal 2022 and Fiscal 2021 (amounts in thousands).

Critical Accounting Policies and Estimates

We consider the accounting policies discussed below related to revenue recognition on long-term construction contracts; income tax reporting; the valuation of goodwill; and the financial reporting associated with any significant claims or legal matters to be most critical to the understanding of our financial position and results of operations, as well as the accounting and reporting for special purpose entities including variable interest entities.

Critical accounting policies are those related to the areas where we have made what we consider to be particularly subjective or complex judgments in arriving at estimates and where these estimates can significantly impact our financial results under different assumptions and conditions.

These estimates, judgments, and assumptions affect the reported amounts of assets, liabilities and equity, the disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets, liabilities and equity that are not readily apparent from other sources. Actual results and outcomes could differ from these estimates and assumptions. We do periodically review these critical accounting policies and estimates with the audit committee of our board of directors.

Revenue Recognition

Our revenues are primarily derived from construction contracts that can span several quarters or years. We enter into EPC and other long-term construction contracts principally on the basis of competitive bids or in conjunction with our support of the development of power plant projects. The types of contracts may vary. However, the EPC contracts of our power industry services reporting segment, and most other large contracts awarded to our other companies, are fixed-price contracts. Revenues are recognized primarily over time as performance obligations are satisfied due to the continuous transfer of control to the project owner or other customer. The accuracy of our revenues and profit recognition in a given period depends on the accuracy of our estimates of the forecasted contract value, or transaction price, and the cost to complete the work for each project.

Central to accounting for revenues from contracts with customers is a five-step revenue recognition model that requires reporting entities to:

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The guidance focuses on the transfer of the control of the goods and/or services to the customer, as opposed to the transfer of risk and rewards. Major provisions cover the determination of which goods and services are distinct and represent separate performance obligations, the appropriate treatment of variable consideration, and the evaluation of whether revenues should be recognized at a point in time or over time. In general, application of the rules requires us to make important judgements and meaningful estimates that may have significant impact on the amounts of revenues recognized by us for any reporting period.

Revenues from fixed price contracts, including a portion of estimated profit, are recognized over time, based on costs incurred and estimated total contract costs using the percentage-of-completion method. The cost and profit estimates are determined at least quarterly for all significant contracts pursuant to a detailed “bottoms-up” review process. The results of the process are subjected to reviews by senior management at each subsidiary. The percentage-of-completion method measures the ratio of costs incurred and accrued to date for each contract to the estimated total cost for each contract at completion. This requires us to prepare on-going estimates of the cost to complete each contract as the project progresses. In preparing these estimates, we make significant judgments and assumptions about our significant costs, including materials, labor and equipment, and we evaluate contingencies based on possible schedule variances, production delays or other productivity factors.

Actual costs may vary from the costs we estimate. Variations from estimated contract costs, along with other risks inherent in fixed-price contracts, may result in actual revenues and gross profits differing from those we estimate and could result in losses on projects or other significant unfavorable impacts on our operating results for any fiscal quarter or year. If a current estimate of total contract cost indicates a loss on a contract, the projected loss is recognized in full when determined, without regard to the percentage of completion. There are a number of factors that can contribute to changes in estimated contract costs, revenues and profitability. The most significant of these are identified in the first item included in the Risks Related to our Operational Execution section of Part I, Item 1A. of this Annual Report entitled Risk Factors.

Crucial to the compliance with the accounting standard covering the recognition of revenues on contracts with customers is the identification of the promises made to the customer by us that are included in the contract. If a promise is distinct, as that concept is defined in the accounting standard, it represents a separate performance obligation. Contracts may have multiple performance obligations. The amounts of revenue associated with each promise are recognized when, or as, the performance obligations are satisfied. However, complex contracts may include only one performance obligation if the multiple promises are not distinct within the context of the contract. For example, if the promises that could be considered distinct are interrelated or require us to perform integration so that the customer receives a complete product, the contract is considered to include only one performance obligation. Most of our long-term contracts have a single performance obligation as the promises to transfer individual goods or services are not separately identifiable from other promises within the context of the contract. Our EPC contracts require us to deliver a complete and functioning power plant, not just functioning components.

The transaction price of a contract represents the value used to determine the amount of revenues recognized as of the balance sheet date. It may reflect amounts of variable consideration, which could be either increases or decreases to the transaction price. These adjustments can be made from time-to-time during the period of contract performance as circumstances evolve related to such items as variations in the scope and price of contracts, claims, incentives and liquidated damages.

The Company may include an estimated amount of variable consideration in the transaction price to the extent it is probable that a significant reversal of cumulative revenues recognized on the particular contract will not occur when the uncertainty associated with the variable consideration is resolved. The Company’s determination of the amount of variable consideration to be included in the transaction price of a particular contract is based largely on an assessment of the Company’s anticipated performance and all information (historical, current and forecasted) that is reasonably available. The effect of any revisions to the transaction price on the amount of previously recognized revenues that is due to the addition or reduction of variable consideration is recorded currently as an adjustment to revenues on a cumulative catch-up basis. In the event that any amounts of variable consideration that are reflected in the transaction price of a contract are not resolved in the Company’s favor, there could be reductions in, or reversals of, previously recognized revenues. In most significant instances, modifications to our contracts do not represent the addition of new performance obligations.

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Contract results may be impacted by estimates of the amounts of contract variations that we expect to receive. The effects of any resulting revisions to revenues and estimated costs can be determined at any time and they could be material. As of January 31, 2021, the aggregate amount of contract variations reflected in estimated contract transaction prices was $16.6 million, including $6.8 million related to our EPC services contract with Exelon. During Fiscal 2022, this amount was recovered in full in connection with the settlement of the litigation with Exelon. As of January 31, 2022, the aggregate amount of contract variations reflected in estimated transaction prices was $7.5 million.

Our long-term contracts typically have schedule dates and other performance obligations that, if not achieved, could subject us to liquidated damages. These contract requirements generally relate to specified activities that must be completed by an established date or by achievement of a specified level of output or efficiency. Each contract defines the conditions under which a project owner may make a claim for liquidated damages. The amounts of liquidated damages owed to a project owner pursuant to the terms of a contract would represent reductions of the transaction price of the corresponding contract.

At the outset of each of the Company’s contracts, the potential amounts of liquidated damages typically are not subtracted, from the transaction price as the Company believes that it has included activities in its contract plan, and has reflected the associated costs in its forecasts of completed contract costs, that will be effective in preventing such damages. Of course, circumstances may change as the Company executes the corresponding contract. The transaction price is reduced by an applicable amount when the Company no longer considers it probable that a future reversal of revenues will not occur when the matter is resolved. In general, we consider potential liquidated damages, the costs of other related items and potential mitigating factors in determining the estimates of forecasted revenues and the adequacy of our estimates of the cost to complete contracts.

Goodwill

In connection with the acquisitions of GPS, TRC and APC, we recorded substantial amounts of goodwill and other purchased intangible assets including contractual and other customer relationships, non-compete agreements, trade names and certain fabrication process certifications. We utilized the assistance of a professional appraisal firm in the initial determinations of goodwill and the other purchased intangible assets for these acquisitions which were all determined to have finite useful lives.

At January 31, 2022, the goodwill balances related to the acquisitions of GPS, TRC and SMC were $18.5 million, $9.5 million and $0.1 million, respectively, which together represented approximately 5.1% of consolidated total assets. The Company performs its required annual assessments of the carrying value of goodwill balances as of November 1 each year. We also test for impairment of goodwill more frequently if events or changes in circumstances indicate that the carrying value of goodwill might be impaired.

In accordance with current accounting guidance, we perform testing for the impairment of goodwill by comparing the estimated fair value of a reporting unit with the carrying amount of the unit reflected in the consolidated financial statements, including goodwill. If the carrying amount of the reporting unit exceeds its estimated fair value, an impairment loss is recorded for the excess, not to exceed the total amount of goodwill allocated to the reporting unit.

The balance of goodwill related to TRC and included in the consolidated balance sheet as of January 31, 2022 was $9.5 million. We performed a goodwill impairment assessment for TRC as of November 1, 2021 with the assistance of a professional business valuation firm. It was determined that the estimated fair value of TRC exceeded the corresponding carrying value by approximately $8.9 million; accordingly, there was no impairment loss recorded as of that date. The estimated fair value amount for TRC determined as of November 1, 2021 reflected a weighting of results determined using various business valuation approaches consistent with prior year valuations.

As in the past, the majority of the weighted average fair value was based on the result of modeling discounted future net-after-tax cash flows of the business. The discounted cash flows of TRC were based on a management forecast of operating results. Last year, the result of a similarly completed assessment of TRC indicated that the excess of its estimated fair value over carrying value was $1.5 million.

Judgments inherent in these approaches include the determination of appropriate discount rates, the amount and timing of expected future cash flows, growth rates for revenues and gross margins, and appropriate benchmark companies. The estimated future cash flows used for TRC were based on five-year financial forecasts developed internally by management.

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Our discount rate assumptions were based on an assessment of the equity cost of capital and the appropriate capital structure for our reporting unit. Material assumptions used in the impairment assessment included the weighted average cost of capital percent and terminal growth rates.

The widening of the excess of estimated fair value over carrying value for TRC during Fiscal 2022 was due primarily to an improved forecast of future results. In view of the strong results reported by TRC during Fiscal 2022, we believe that the current forecast of the operating results of TRC is based on reasonable assumptions and, in particular, the following factors. The average amount of annual revenues during the five-year period ending January 31, 2027 is forecasted to be $102.2 million, with a terminal revenues annual growth rate of 3% thereafter. The actual amount of revenues recognized by TRC for Fiscal 2022 was $97.9 million. Annual earnings before interest and taxes are forecast to increase from 4.8% of revenues for the year ending January 31, 2023 to 6.2% of revenues by the year ending January 31, 2027, with a terminal percentage of 6.8% of corresponding revenues. The actual amount of such earnings for Fiscal 2022 was 11.6% of corresponding revenues. Should unfavorable operating results in the future indicate that the forecast for TRC is too optimistic, we may reduce it. This could result in a shrinking of the excess or even a future impairment loss.

In certain situations, we use an alternative approach which allows us to first assess qualitative factors to decide whether it is necessary to perform the quantitative goodwill impairment test. We are not required to calculate the fair value of a reporting unit unless we determine, based on a qualitative assessment, that it is more likely than not that its fair value is less than the corresponding carrying value. The professional guidance includes discussions of the types of factors which should be considered in conducting the qualitative assessment including macroeconomic, industry, market and entity-specific factors. Using this approach, we concluded that it was more likely than not that the fair value of the GPS reporting unit exceeded the corresponding carrying value as of November 1, 2021. Therefore, completion of the quantitative impairment assessment was considered to be unnecessary. No events associated with the business of GPS occurred in the period from the assessment date through January 31, 2022 that would cause us to reconsider that conclusion.

Uncertain Income Tax Positions

As we have disclosed in the “Research and Development Tax Credits” section of Note 13 to the accompanying consolidated financial statements, during Fiscal 2019 we completed a detailed review of the activities of our engineering staff on major EPC services projects in order to identify and quantify the amounts of research and development credits available to reduce prior year income taxes. This extensive study focused on the costs incurred on specific projects during the three-year period ended January 31, 2018. Based on the results of the study, we identified and estimated significant amounts of income tax benefits that were not previously recognized in our financial results for any prior year reporting period.

Under current professional accounting guidance, income tax positions must meet a more-likely-than-not recognition threshold to be recognized. Income tax positions that previously failed to meet the more-likely-than-not threshold are recognized in the first subsequent financial reporting period in which that threshold is met. Fiscal 2019 was the initial reporting period in which we had sufficient data on which to make an evaluation and to reach a conclusion on the amount of income tax credit benefits related to prior year project costs that, more likely than not, qualified as research and development costs under the Internal Revenue Code and the rules and regulations of certain states. The net amount of the credits that we recognized in income taxes during Fiscal 2019 was $16.2 million, as subsequently reduced by $0.4 million. Based on our judgement, the amount of income tax benefits related to identified research and development income tax credits that we assessed as not meeting the threshold criteria for recognition was $5.1 million, for which we established a liability related to uncertain income tax return positions that was included in accrued expenses as of January 31, 2019. During Fiscal 2020, this amount was adjusted modestly; the liability amount as of January 31, 2022 and 2021 was $5.0 million.

The research and development credits were included in amendments to our consolidated federal income tax returns for Fiscal 2016 and Fiscal 2017, that were filed in January 2019, and our consolidated federal income tax return for Fiscal 2018, that was filed in November 2018. During Fiscal 2022, the IRS issued its revenue agents reports that disagree with our credit amounts. The differences in amounts are meaningful.

After a careful review of a preliminary reports received from the IRS, the preparation of an acknowledgement-of-facts responses, analysis of the final reports and consultation with subject experts, we have concluded that our arguments are sound based on our analysis of the facts, our understanding of the tax code and related regulations and our understanding

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of the applicable case law, and that the reports do not present any new facts relating to the issues or make any new arguments that would cause us to make any adjustments to our accounting for the research and development claims as of January 31, 2022. We have formally protested the findings of the IRS examiner and are pursuing our income tax positions with the IRS through the established appeals process. We expect that our appeals hearing will occur during Fiscal 2023.

We have updated the evaluation of our income tax positions using the more-likely-than-not threshold in order to confirm the adequacy of the liability amount carried in the balance sheet as of January 31, 2022 for uncertain income tax positions. We have not adjusted the liability amount during Fiscal 2022 as we do not anticipate any significant changes to the net amount of the income tax benefits recorded for research and development credits claimed for Fiscal 2016 through Fiscal 2018. However, if negotiations with the IRS or legal decisions cause us to believe that our previously recognized tax positions no longer meet the more-likely-than-not threshold, the related net tax benefit amount will be derecognized in the first financial reporting period in which that threshold is no longer met. Any unfavorable adjustment to our taxes could reverse a substantial portion of the amount of net research and development credits recognized of $16.2 million, which could materially and adversely affect our future financial condition and operating results.

Deferred Tax Assets and Liabilities

Our consolidated balance sheet as of January 31, 2022 includes net deferred tax assets in the amount of approximately $0.5 million. The components of our deferred taxes are presented in Note 13 to the accompanying consolidated financial statements. These amounts reflect differences in the periods in which certain transactions are recognized for financial and income tax reporting purposes.

We consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized on a jurisdiction-by-jurisdiction basis. Our ability to realize our deferred tax assets, including those related to the past NOLs incurred in the U.K., that applicable income tax rules will allow us to use in order to offset future amounts of applicable taxable income, depends primarily upon the generation of sufficient future taxable income to allow for the realization of our deductible temporary differences. If such estimates and assumptions regarding income amounts change in the future, we may be required to record additional valuation allowances against some or all of the deferred tax assets resulting in additional income tax expense in our consolidated statement of earnings. During Fiscal 2020, a valuation allowance in the amount of $7.1 million was established against the deferred tax asset amount created by the NOL of APC’s subsidiary in the U.K. for Fiscal 2020. However, we believe that the results of operations in the U.K. have begun a turnaround that should enable APC to utilize portions of the unrecognized NOL benefits in the future.

A deferred tax asset in the amount of $8.3 million was recorded as of January 31, 2020 associated with the income tax benefit of our domestic NOL for Fiscal 2020 without any corresponding valuation allowance. Among other changes, the CARES Act re-established a carryback period for certain losses to five years. The NOLs eligible for carryback under the CARES Act include our domestic loss for Fiscal 2020, which was approximately $39.5 million. We have made the appropriate filing with the IRS requesting carryback refunds of income taxes paid for the years ended January 31, 2017, 2016 and 2015. With the enactment of the CARES Act, the asset amount was moved to income taxes receivable representing a complete utilization of the NOL within one year of its occurrence.

At this time, we believe that the historically strong earnings performance of our power industry services segment will provide sufficient income during the years when most of our other deferred tax assets become deductible in the U.S. in order for us to realize the applicable temporary income tax differences. Accordingly, we believe that it is more likely than not that we will realize the benefit of significantly all of our net deferred tax assets.

Variable Interest Entities

This Item 7 of the 2022 Annual Report and Note 3 of the accompanying consolidated financial statements include discussions of “Special Purpose Entities” that include variable interest entities. Determinations are made by management regarding the accounting and disclosures for these entities including, for example, the identification of variable interests and the consideration of control over the primary activities of the entities. During Fiscal 2022, the most important determination related to the valuation of project development costs in our consolidated balance sheet. As explained in the sections of this 2022 Annual Report identified above, we recorded an impairment loss in the amount of $7.9 million during Fiscal 2022 as we came to the conclusions that the related natural gas-fired power plant project was not viable and that our costs would not be recovered. In March 2022, the project owner made a public announcement that the power plant project, planned to be built in Virginia, was cancelled.

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Legal Contingencies

We do become involved in legal matters where litigation has been initiated or claims have been made against us. At this time, we do not believe that any material loss is probable related to any current matters. We do maintain accrued expense balances for the estimated amounts of legal costs expected to be billed related to any significant matter. We review the status of each matter and assess the adequacy of the accrued expense balances at the end of each fiscal quarter, and make adjustments to the balances if necessary. Should our assessments of the outcomes of outstanding legal matters change, significant losses or additional costs may be recorded.

During Fiscal 2022, the significant legal matter described below, for which we have been providing regular disclosure in our filings, was settled.

In January 2019, GPS filed a lawsuit against Exelon West Medway II, LLC and Exelon Generation Company, LLC (together referred to as “Exelon”) for Exelon’s breach of contract and failure to remedy various conditions which negatively impacted the schedule and the costs associated with the construction by GPS of a gas-fired power plant for Exelon in Massachusetts. Subsequently, Exelon provided GPS with a notice intending to terminate the EPC contract under which GPS had been providing services to Exelon and served us with contractual notice requiring GPS to vacate the construction site. At that time, the construction project was nearly complete and both of the power generation units included in the plant had successfully reached first fire. The completion of various prescribed performance tests and the clearance of punch-list items were the primary tasks necessary to be accomplished by GPS in order to achieve substantial completion of the power plant. Exelon asserted that GPS failed to fulfill certain obligations under the contract and was in default, withholding payments from GPS on invoices rendered to Exelon in accordance with the terms of the contract between the parties.

Our firm belief that Exelon received the benefits of the construction efforts of GPS and the corresponding progress made on the project without making payments to GPS for the value received was reflected in our accounting for the project that we maintained throughout the duration of the dispute. There were outstanding invoices billed to Exelon and unbilled costs incurred on the project, with substantial balances included in both accounts receivable and contract assets as of January 31, 2021. The final settlement of all outstanding claims between the parties resulting in Exelon making a payment to GPS in the amount of $27.5 million, which amount was in excess of the total carrying amount of the related accounts receivable and contract assets. The excess amount was included in revenues for Fiscal 2022.

Recently Issued Accounting Pronouncements

In December 2019, the Financial Accounting Standards Board issued Accounting Standards Update 2019-12, Simplifying the Accounting for Income Taxes, which, among other changes, eliminates the exception to the general methodology for calculating income taxes in an interim period when a year-to-date loss exceeds the expected loss for the entire year. In these instances, the estimated annual effective income tax rate shall be used to calculate the tax without limitation. The new standard also requires the recognition of a franchise (or similar) tax that is partially based on income as an income-based tax and the recording of any incremental tax that is incurred by us as a non-income-based tax. The requirements of this new guidance, effective for us on February 1, 2021, did not alter our accounting for income taxes.

There are no other recently issued accounting pronouncements that have not yet been adopted that we consider material to our consolidated financial statements.