ARGAN INC (AGX) FY 2024 MD&A

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

- 29 -

Table of Contents

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

- 30 -

Table of Contents

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.

- 31 -

Table of Contents

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.

- 32 -

Table of Contents

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.

- 33 -

Table of Contents

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

- 34 -

Table of Contents

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

- 35 -

Table of Contents

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.

- 36 -

Table of Contents

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.

- 37 -

Table of Contents

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):

- 38 -

Table of Contents

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.

- 39 -

Table of Contents

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.

- 40 -

Table of Contents

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.

- 41 -

Table of Contents

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

- 42 -

Table of Contents

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.

- 43 -

Table of Contents

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

- 44 -

Table of Contents

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

- 45 -

Table of Contents

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.

- 46 -

Table of Contents

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.

- 47 -

Table of Contents

Recently Issued Accounting Pronouncements

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