ARGAN INC (AGX) FY 2023 MD&A

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.

- 29 -

Table of Contents

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.

- 30 -

Table of Contents

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.

- 31 -

Table of Contents

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.

- 32 -

Table of Contents

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.

- 33 -

Table of Contents

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.

​

- 34 -

Table of Contents

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

- 35 -

Table of Contents

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.

- 36 -

Table of Contents

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

- 37 -

Table of Contents

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.

- 38 -

Table of Contents

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.

- 39 -

Table of Contents

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.

- 40 -

Table of Contents

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

- 41 -

Table of Contents

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.

- 42 -

Table of Contents

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.

- 43 -

Table of Contents

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.

- 44 -

Table of Contents

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

- 45 -

Table of Contents

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.

- 46 -

Table of Contents

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

- 47 -

Table of Contents

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.