Argan Inc: Form 10-Q for the period ended Oct 31, 2023

The following discussion summarizes the financial position of Argan, Inc. and its subsidiaries as of October 31, 2023, and the results of their operations for the three and nine month periods ended October 31, 2023 and 2022, and should be read in conjunction with (i) the unaudited condensed consolidated financial statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q and (ii) the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for Fiscal 2023 that was filed with the SEC on April 17, 2023 (the “Annual Report”).

Cautionary Statement Regarding Forward Looking Statements

The Private Securities Litigation Reform Act of 1995 provides a “safe harbor” for certain forward-looking statements. We have made statements in this Item 2 and elsewhere in this Quarterly Report on Form 10-Q 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 this Quarterly Report on Form 10-Q and our 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, 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 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, 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

For the reporting periods ended October 31, 2023 and as described below, we recorded a significant loss related to a construction project in the U.K. Despite the loss, we reported an increase in our pre-tax book income compared to last year. We did not record a tax benefit related to this net operating loss. As a result, we are reporting a reduction in net income between quarters. For the nine months ended October 31, 2023, the strength of the operating results reported by all of our business, plus the increase in the returns earned on our invested cash, were sufficient to cause our net income to increase, although slightly, between years.

Consolidated revenues for the three months ended October 31, 2023 were $163.8 million, which represented an increase of $45.9 million, or 38.9%, from consolidated revenues of $117.9 million reported for the three months ended October 31, 2022. The overall improvement in revenues was due to increases in revenues between quarters for both the power industry and industrial construction services reportable segments.

Consolidated gross profit for the three-month period ended October 31, 2023 was $19.2 million, or approximately 11.7% of the corresponding consolidated revenues, which reflected positive contributions from all three reportable business segments. However, the consolidated gross profit for the quarter was adversely impacted by the recorded loss of $10.7 million related to APC’s construction contract in Northern Ireland. For the three-month period ended October 31, 2022, the consolidated gross profit was $22.2 million, which represented approximately 18.8% of the corresponding amount of consolidated revenues.

Selling, general and administrative expenses for the three months ended October 31, 2023 and 2022 were $11.4 million, or 6.9% of corresponding consolidated revenues, and $12.7 million, or 10.7% of corresponding consolidated revenues, respectively.

Other income, net, for the three months ended October 31, 2023 was $3.7 million, which substantially related to income earned during the period on cash, cash equivalents and investments.

For the three months ended October 31, 2023, income tax expense was $6.1 million which represented an effective income tax rate of 52.9%. For the three months ended October 31, 2022, income tax expense was $2.6 million, which represented an effective income tax rate of 24.7% for the period.

Consolidated revenues for the nine months ended October 31, 2023 were $408.8 million, which represented an increase of $72.5 million, or 21.6%, from consolidated revenues of $336.3 million reported for the nine months ended October 31, 2022, with the power industry and industrial construction services reportable segments both contributing to the increase.

Consolidated gross profit for the nine-month period ended October 31, 2023 was $57.2 million, or approximately 14.0% of the corresponding consolidated revenues, which reflected positive contributions from all four of our operating companies, including APC. However, the $11.5 million of loss that was recorded during the nine-month period ended October 31, 2023, related to APC’s contract in Northern Ireland, adversely impacted the consolidated gross profit for the period. For the nine-month period ended October 31, 2022, the consolidated gross profit was $66.3 million, which represented approximately 19.7% of the corresponding amount of consolidated revenues.

Selling, general and administrative expenses for the nine months ended October 31, 2023 and 2022 were $32.5 million, or 7.9% of corresponding consolidated revenues, and $34.2 million, or 10.2% of corresponding consolidated revenues, respectively.

Other income, net, for the nine months ended October 31, 2023 was $7.2 million, which primarily reflected income earned during the period on invested funds, partially offset by the wire-transfer fraud loss that occurred in the first quarter of Fiscal 2024, its partial recovery, and related professional fees (see Note 15 to the accompanying condensed consolidated financial statements). Other income, net, for the nine months ended October 31, 2022 was $1.9 million, which included primarily our share of earnings associated with our solar fund investments and income earned on funds maintained in money market accounts and interest income earned on CDs.

For the nine months ended October 31, 2023, income tax expense was $11.6 million which represented an effective income tax rate of 36.3%. For the nine months ended October 31, 2022, income tax expense was $14.5 million.

For the three months ended October 31, 2023, our overall operating profit performance resulted in net income in the amount of $5.5 million, or $0.40 per diluted share. For the comparable period last year, we reported net income in the amount of $7.8 million, or $0.56 per dilutive share. For the nine months ended October 31, 2023, our net income increased to $20.3 million, or $1.50 per diluted share, from $19.5 million, or $1.36 per diluted share, for the nine months ended October 31, 2022.

Project Backlog

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

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. However, cancellations or reductions may occur that would reduce project backlog and that could adversely affect our expected future revenues.

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 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 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.

In August 2023, GPS executed Limited Notices to Proceed (“LNTPs”) with Vistra Energy for three solar and battery projects in Illinois. Under the LNTPs, GPS has 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. The projects will represent 160 MW of electrical power and 22 MW of energy storage.

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. We received the full notice to proceed from the project from the 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 late in the year ending January 31, 2026.

During the first quarter of Fiscal 2024, we achieved the substantial completion milestone for the Guernsey Power Station, which is located in Cambridge, Ohio, pursuant to an EPC services contract with Caithness Energy, L.L.C. This 1,875 MW, combined cycle power plant remains the largest single-phase, gas-fired, electricity-generation plant in the U.S. A small portion of our consolidated project backlog at October 31, 2023 relates to this project as GPS continues to pursue the closeout of remaining commercial matters with the customer, certain subcontractors and equipment suppliers. During the quarter ended October 31, 2023, GPS primarily completed the final stages of the commissioning process, including punch-list items and demobilization efforts. Final completion of this project is currently expected to occur during the fourth quarter of Fiscal 2024.

In November 2023, we achieved substantial completion of the Maple Hill Solar facility, which is among the largest solar-powered energy plant 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 is expected prior to the end of 2023.

Together, the Trumbull Energy Center, the Guernsey Power Station, the Maple Hill Solar facility and the Illinois solar and battery projects represent over 3.0 gigawatts of potential electrical power. Additionally, the technical, project support and project management teams of GPS continue to assist APC with certain current projects and business development efforts, which broadened the project backlog of this business to approximately $95 million as of October 31, 2023, including the remaining value of an engineering and construction services contract with EPNI Energy Limited (“EP”). APC 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. This project is hereinafter referred to as the “Kilroot” project.

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 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 2024.

Additionally, APC entered into an EPC services contract with GE Vernova for the Shannonbridge Project, 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, 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 this year 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 2024.

The project backlog of TRC has increased by nearly 200% since the end of Fiscal 2022 to approximately $132 million as of October 31, 2023, reflecting a business development emphasis on the award of larger industrial field service construction projects from continuing and new customers. 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.

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 unresolved project-related matters continue to meaningfully impact the contract, our costs and the project schedule negatively. At October 31, 2023, APC’s estimates of the unfavorable financial impacts due to difficulties on the Kilroot project escalated substantially. APC recently conducted an updated and comprehensive review of the costs of the efforts to complete the remaining contract work. We believe that the estimated costs of APC at the completion of the Kilroot project will exceed projected revenues by $7.9 million. The amount of this loss, plus the unfavorable adjustment of estimated gross profit of approximately $2.8 million recognized in previous periods in connection with the project, was reflected in our operating results for the three-month period ended October 31, 2023. 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 estimates that it is approximately 95% complete with design and construction. It is currently commissioning the facility and it expects to be ready for the first fire of both gas turbines by early 2024. 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.

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 the U.S. 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 COVID-19 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 upward. As a result, the price of natural gas in the U.S. increased meaningfully during 2022. However, spot prices have declined throughout 2023 but are forecasted to rise again in 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 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. 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 is forecasted to 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.

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. 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 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.

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 imposes new taxes on corporations with net profits for financial reporting in excess of $1.0 billion, spends billions of dollars over a decade on new workers and technology at the IRS, and 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. 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.

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, that are providing base load power, flexibility in choosing the means to achieve the emission targets. Alternatives could include the installation of carbon-capture systems that remove carbon dioxide from flue gases that are the by-product of fossil-fuel combustion 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. A public comment period for the proposed rules ended in early August 2023; 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 process. Such streamlining of the current permitting process for energy generating facilities could ease certain constraints on the power industry.

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 has already occurred as 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% from 2030 through 2050. 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.

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, with over 80% of new power capacity coming from renewables last year. 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 ongoing transition is marked by emerging technologies like hydrogen, and the declining costs of electric vehicles, further emphasizing the dynamic evolution of the renewable energy landscape.

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 Interconnection (“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 the Mid-Atlantic region of the U.S. 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. After multiple delays, the auctions for the 2023/2024 and 2024/2025 delivery years, were conducted. However, prices were significantly lower than each previous auction. In June 2023, the Federal Energy Regulatory Commission (“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. PJM filed its proposal of capacity market enhancements with the FERC in October 2023.

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.

Providing a basis for a belief that new gas plants will have a role in an electrified future dominated by renewables is the need for grid reliability and sustainability, 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. While acknowledging the reality of the power transition in the PJM system, it warned that 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 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 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 cleaner forms of energy such as wind and solar 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.

In the U.S., local electricity grids are connected to form larger networks, known as Regional Transmission Operators (“RTOs”) and Independent System Operators (“ISOs”), to improve reliability and economic efficiency. The U.S. is divided into three main interconnections of which these networks are members: 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 systems. All RTOs, including PJM, and ISOs in the U.S. are balancing authorities. Consequently, reliability threats to certain 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. 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 account 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.

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 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 approximately 40 years old with most plants authorized to operate for another 20 years. Two U.S.-based nuclear reactors, Vogtle Units 3 and 4, began construction 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 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, but could provide balance-of-plant construction opportunities for GPS.

Therefore, 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, 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 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. 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.

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.

The foregoing discussion in this “Market Outlook” does focus on the state of the domestic power market as the EPC services business of GPS historically 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 but including nuclear power in the U.K.

The Irish government has issued a policy statement on the security of the electricity supply in Ireland which confirms the requirement for the development of new support technologies to deliver on its commitment to have 80% of the country’s electricity generated from renewables by 2030. The report emphasizes that this will require a combination of conventional generation (typically powered by natural gas), interconnection to other jurisdictions, demand flexibility and other technologies such as battery storage and generation from renewable gases. 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. Additionally, the Shannonbridge Project, for which APC received full notice to proceed in August 2023 to construct eight turbine units capable of producing 264 MW of power, is an initiative of EirGrid and the ESB that aims to ensure reliable electricity supply during critical situations and emergencies.

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.

APC is actively pursuing other new business opportunities in both the renewable and support sectors of power generation with its existing and new clients. Over the last three years, APC has increased its activities and currently has five 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 Project.

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.

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 its field-services focus 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 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. The project backlog of TRC grew by over 175% from January 31, 2022 to approximately $123.5 million as of January 31, 2023, reflecting TRC’s business development emphasis on the award of larger industrial construction projects.

Recent and current major customers of TRC include Nutrien Ltd., the global fertilizer company; Livent Corporation, a global lithium technology 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; OceanaGold Corporation, a gold-mining company located in South Carolina; Air Liquide S.A., a world leading supplier of industrial gases; North America’s largest forest products companies such as Weyerhaeuser Company 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 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 business-friendly local and state governments that welcome industrial production facilities with ideal locations and with serious economic development programs and incentives. 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, 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 ongoing inflation, 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 Inflation Reduction Act and the Creating Helpful Incentives to Produce Semiconductors Act, and appear to be sustaining high construction industry confidence for 2024 and the future beyond.

Comparison of the Results of Operations for the Three Months Ended October 31, 2023 and 2022

We reported net income of $5.5 million, or $0.40 per diluted share, for the three months ended October 31, 2023. For the comparable period of the prior year, we reported net income of $7.8 million, or $0.56 per diluted share. The following schedule compares our operating results for the three months ended October 31, 2023 and 2022 (dollars in thousands):

Revenues

Power Industry Services

The revenues of the power industry services segment, representing the businesses of GPS and APC, increased by 33.8%, or $30.6 million, to $121.3 million for the three months ended October 31, 2023 compared with revenues of $90.7 million for the three months ended October 31, 2022 as the quarterly construction activities increased for the Shannonbridge Power Project, the Trumbull Energy Center, and the ESB FlexGen peaker plants. The increase in revenues between quarters was partially offset by decreased construction activities associated with the Guernsey Power Station project and Maple Hill Solar energy facility, as those projects are generally near or at completion. The revenues of this business segment represented approximately 74.1% of consolidated revenues for the quarter ended October 31, 2023 and 76.9% of consolidated revenues for the corresponding prior year quarter.

The primary driver for the revenues of this segment for the three months ended October 31, 2022 were the revenues associated with the construction of the Guernsey Power Station, the Maple Hill Solar energy facility, the ESB FlexGen peaker plants and the Kilroot power facility.

Industrial Construction Services

The revenues of our industrial construction services segment, representing the business of TRC, increased by $16.3 million, or 73.6%, to $38.4 million for the three months ended October 31, 2023 compared to revenues of $22.1 million for the three months ended October 31, 2022 as the amounts of field services and supporting vessel fabrication work increased meaningfully between periods. For the three months ended October 31, 2023 and 2022, the revenues of this segment represented 23.5% and 18.8% of consolidated revenues for the corresponding periods.

Telecommunications Infrastructure Services

The revenue results of this business segment, which represent the business of SMC, were $4.0 million for the three-month period ended October 31, 2023, a decrease of $1.0 million, or 20.5%, from the amount of revenues earned during the three months ended October 31, 2022.

Cost of Revenues

With the increase in consolidated revenues for the three months ended October 31, 2023 compared with last year’s third quarter ended October 31, 2022, the consolidated cost of revenues also increased between the quarters. These costs were $144.5 million and $95.7 million for the three-month periods ended October 31, 2023 and 2022, respectively, representing an increase of approximately 51.1%.

For the three-month period ended October 31, 2023, we reported a consolidated gross profit of approximately $19.2 million which represented a gross profit percentage of approximately 11.7% of corresponding consolidated revenues, and a decrease from the gross profit reported for the three-month period ended October 31, 2022 in the amount of $22.2 million. The reduction was primarily due to the unfavorable gross profit adjustment on the Kilroot project in the amount of $10.7 million that was recorded in the current quarter. The effect of the contract loss was meaningfully offset for the current quarter by the profits earned on the performance of other projects by each of our four operating companies, including APC. The gross profit percentages of corresponding revenues for the power industry services, industrial construction services and the telecommunications infrastructure services segments were 11.1%, 11.8% and 29.4%, respectively, for the quarter ended October 31, 2023.

Our consolidated gross profit reported for the three-month period ended October 31, 2022 of $22.2 million represented a gross profit percentage of approximately 18.8% of corresponding consolidated revenues. The gross profit percentages of corresponding revenues for the power industry services, industrial construction services and the telecommunications infrastructure services segments were 19.8%, 15.4% and 16.8%, respectively, for the quarter ended October 31, 2022.

Selling, General and Administrative Expenses

These costs were $11.4 million and $12.7 million for the three months ended October 31, 2023 and 2022, respectively, and represented 6.9% and 10.7% of corresponding consolidated revenues, respectively.

Other Income, Net

Other income, net, for the three months ended October 31, 2023 was $3.7 million, which reflected income earned during the period on funds invested in a money market account, CDs, U.S. Treasury notes and a U.S. corporate debt security in the total amount of approximately $4.0 million, as investment yields and average balances of invested funds are meaningfully higher this year.

We reported other income, net, in the amount of $0.8 million for the three months ended October 31, 2022, which included primarily income earned on funds maintained in a money market account and interest income earned on CDs.

Income Taxes

We incurred income tax expense for the three months ended October 31, 2023 in the amount of approximately $6.1 million, which represents an effective income tax rate of 52.9%. This effective tax rate differs from the statutory federal tax rate of 21% due primarily to the typically unfavorable estimated effects of state income taxes and permanent differences, including certain nondeductible executive compensation and an unrecognized tax loss benefit for the current fiscal quarter. We did not record an income tax benefit related to the net operating loss incurred by our subsidiary in the U.K. that is building the

Kilroot power plant. This accounting resulted in our effective income tax rate increasing from 27.1% to 52.9% for the quarter. For the three months ended October 31, 2022, we reported income tax expense in the amount of approximately $2.6 million, which represented an effective tax rate of 24.7% for the period.

Comparison of the Results of Operations for the Nine Months Ended October 31, 2023 and 2022

We reported net income of $20.3 million, or $1.50 per diluted share, for the nine months ended October 31, 2023. For the comparable period of the prior year, we reported net income of $19.5 million, or $1.36 per diluted share. The following schedule compares our operating results for the nine months ended October 31, 2023 and 2022 (dollars in thousands):

Revenues

Power Industry Services

The revenues of the power industry services segment increased by $40.9 million, or 16.0%, to $296.8 million for the nine months ended October 31, 2023 compared with revenues of $256.0 million for the nine months ended October 31, 2022 as the current year construction activities increased for the Shannonbridge Power Project, the Trumbull Energy Center and the ESB FlexGen peaker plants. The increase in revenues between years was partially offset by decreased construction activities associated with the Guernsey Power Station project, the Maple Hill Solar energy facility and APC’s Equinix data center project, as those projects are generally near or at completion. The revenues of this business segment represented approximately 72.6% of consolidated revenues for the nine-month period ended October 31, 2023, and 76.1% of consolidated revenues for the nine-month period ended October 31, 2022.

The primary drivers for the revenues of this segment for the nine months ended October 31, 2022 were the revenues associated with the construction of the Guernsey Power Station, the Maple Hill solar energy facility, the Kilroot Power Station and the ESB FlexGen peaker plants.

Industrial Construction Services

The revenues of our industrial construction services segment, increased by $33.8 million, or 50.0%, to $101.5 million for the nine months ended October 31, 2023 compared to revenues of $67.7 million for the nine months ended October 31, 2022 as the amounts of field services and, particularly, vessel fabrication work in support of field services increased between periods. For the nine months ended October 31, 2023 and 2022, the revenues of this segment represented 24.8% and 20.1% of consolidated revenues for the corresponding periods.

Telecommunications Infrastructure Services

The revenues of this business segment were $10.5 million for the nine-month period ended October 31, 2023, a decrease of $2.2 million, or 17.3%, from the amount of revenues earned during the nine months ended October 31, 2022.

Cost of Revenues

With the increase in consolidated revenues for the nine months October 31, 2023 compared with last year’s nine-month period ended October 31, 2022, the consolidated cost of revenues also increased between the periods. These costs were $351.6 million and $269.9 million for the nine-month periods ended October 31, 2023 and 2022, respectively, representing an increase of approximately 30.2%.

For the nine-month period ended October 31, 2023, we reported a consolidated gross profit of approximately $57.2 million, which represented a gross profit percentage of approximately 14.0% of corresponding consolidated revenues, a decrease from the gross profit reported for the nine-month period ended October 31, 2022 in the amount of $66.3 million. The consolidated gross profit for the nine months ended October 31, 2023 was adversely affected by the loss recorded for the Kilroot project with substantial offset from the profits earned on other major projects by each of our four businesses. The gross profit percentages of corresponding revenues for the power industry services, industrial construction services and the telecommunications infrastructure services segments were 14.0%, 12.8% and 25.1%, respectively, for the nine months ended October 31, 2023.

Our consolidated gross profit reported for the nine-month period ended October 31, 2022 represented a gross profit percentage of approximately 19.7% of corresponding consolidated revenues. The gross profit percentages of corresponding revenues for the power industry services, industrial construction services and the telecommunications infrastructure services segments were 20.7%, 15.8% and 21.1%, respectively, for the nine months ended October 31, 2022.

Selling, General and Administrative Expenses

These costs were $32.5 million and $34.2 million for the nine months ended October 31, 2023 and 2022, respectively, and represented 7.9% and 10.2% of corresponding consolidated revenues, respectively.

Other Income, Net

Other income, net, for the nine months ended October 31, 2023 was $7.2 million, which reflected approximately $9.7 million of income earned during the period on invested funds, as investment yields and average balances of funds invested are meaningfully higher this year, partially offset by the wire-transfer fraud loss of $3.0 million that occurred in the first quarter of Fiscal 2024 and $0.2 million in related professional fees. Also included in other income are approximately $0.4 million in funds that have been recovered from the wire-transfer fraud loss through legal efforts and insurance proceeds (see Note 15 to the accompanying condensed consolidated financial statements).

We reported other income, net, in the amount of $1.9 million for the nine months ended October 31, 2022, which included primarily earnings associated with our solar fund investments and income earned on funds maintained in a money market account and interest income earned on CDs.

Income Taxes

We incurred income tax expense for the nine months ended October 31, 2023 in the amount of approximately $11.6 million, which represents an effective income tax rate of 36.3%. This estimated tax rate differs from the statutory federal tax rate of 21% due primarily to the typically unfavorable estimated effects of state income taxes and permanent differences, including certain nondeductible executive compensation and an unrecognized tax loss benefit for the current year. As described above, income tax expense for the current year excludes any income tax benefit associated with the year-to-date net loss of our subsidiary in the U.K. This accounting caused the effective income tax rate to increase from 25.8% to 36.3% for the period. For the nine months ended October 31, 2022, we reported income tax expense in the amount of approximately $14.5 million, including an unfavorable adjustment in the approximate amount of $6.2 million related to the settlement of research and development credit claims with the IRS. Excluding the effect of this adjustment, our effective income tax rate for the nine-months ended October 31, 2022 was 24.5%.

Liquidity and Capital Resources as of October 31, 2023

At October 31 and January 31, 2023, our balances of cash and cash equivalents were $185.6 million and $173.9 million, respectively, which represented an increase of $11.7 million.

The net amount of cash provided by operating activities for the nine months ended October 31, 2023 was $92.3 million. Our net income for the nine months ended October 31, 2023, adjusted favorably by the net amount of non-cash income and expense items, represented a source of cash in the total amount of $25.8 million. The increase of other assets of $3.0 million, represented a use of cash primarily due to the increase of prepaid assets during the period. The increase in the combined level of accounts payable and accrued expenses in the amount of $10.0 million, represented a source of cash during the period. The increase in contract liabilities of $59.9 million represented a source of cash, primarily due to the net effect of the early phase of construction activities on a GPS project and the post peak phases of certain APC projects.

During the nine months ended October 31, 2023, 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 $2.1 million to make capital expenditures.

For the nine months ended October 31, 2023, we used $18.0 million cash in financing activities, including $8.5 million used to repurchase shares of common stock pursuant to our share repurchase program and $10.7 million used for the payment of regular cash dividends. We received proceeds from the exercise of stock options in the amount of $1.4 million, which represented a source of cash. Payments of $0.3 million for withholding taxes reimbursed by shares represented a use of cash during the period. As of October 31, 2023, there were no restrictions with respect to intercompany payments between the holding company, GPS, TRC, APC and SMC.

During the nine months ended October 31, 2022, our balance of cash and cash equivalents decreased by a net amount of $214.4 million and our working capital decreased by $53.8 million to $230.4 million as of October 31, 2022 from $284.3 million as of January 31, 2022.

The net amount of cash used in operating activities for the nine months ended October 31, 2022 was $73 million. Our net income for the nine months ended October 31, 2022, adjusted favorably by the net amount of non-cash income and expense items, represented a source of cash in the total amount of $25.2 million. However, reductions in the balance of contract liabilities and the combined level of accounts payable and accrued expenses in the amounts of $78.9 million and $8.0 million, respectively, represented uses of cash. Both of these reductions related primarily to the decline in the construction activity of the Guernsey Power Station project, partially offset by an increase in contract liabilities at several APC projects. Additionally, the increase in contract assets and accounts receivable in the amounts of $6.6 million and $10.9 million, respectively, represented uses of cash during the period. The decrease in the amount of other assets in the amount of $6.2 million, represented a source of cash during the period.

During the nine months ended October 31, 2022, we also 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 $2.6 million. We also used $73.8 million cash in financing activities during the nine months ended October 31, 2022, including $63.3 million used to repurchase shares of common stock pursuant to our share repurchase program, and $10.6 million used for the payment of regular cash dividends.

At October 31, 2023, a portion of our balance of cash and cash equivalents was invested in certificates of deposit and a money market fund with most of its net assets invested in cash, U.S. Treasury obligations and repurchase agreements secured by U.S. government obligations. The major portion of our domestic operating bank account balances are maintained with the Bank. We do maintain certain Euro-based bank accounts in Ireland and certain pound sterling-based bank accounts in the U.K. in support of the operations of APC.

In order to monitor the actual and necessary levels of liquidity for our business, we focus on net liquidity, or working capital, in addition to our cash balances. During the nine months ended October 31, 2023, our net liquidity increased by $4.0 million to $240.2 million from $236.2 million as of January 31, 2023, due primarily to our net income for the period, 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 the expiration date of the Credit Agreement 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 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 October 31, 2023, we had no outstanding borrowings. However, the Bank has issued letters of credit in the total outstanding amount of $13.2 million as of October 31, 2023, in support of the activities of APC under existing customer contracts, including $8.9 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 October 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 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 October 31, 2023 and January 31, 2023, the estimated amounts of the Company’s unsatisfied bonded performance obligations, covering all of its subsidiaries, were approximately $0.5 billion and $0.6 billion, respectively. As of October 31, 2023 and January 31, 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 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 October 31, 2023 are not estimable.

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. To date, we have received substantially all of the income tax benefits associated with the investments. 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, 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.

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

The table following immediately below presents the determinations of EBITDA for the three and nine months ended October 31, 2023 and 2022, respectively (amounts in thousands).

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

However, as EBITDA is not a measure of performance calculated in accordance with U.S. GAAP, we do not believe that this measure should be considered in isolation from, or as a substitute for, the results of our operations presented in accordance with U.S. GAAP that are included in our condensed 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.

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; 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. An expanded discussion of our critical accounting policies is included in Item 7 of Part II of our Annual Report. During the nine months ended October 31, 2023, there have been no material changes in the way we apply the critical accounting policies described therein.

Recently Issued Accounting Pronouncements

See Note 1 to the accompanying condensed consolidated financial statements for discussion on recently issued accounting pronouncements.

In the normal course of business, our results of operations may be subject to risks related to fluctuations in interest rates. As of October 31, 2023, we had no outstanding borrowings under our financing arrangements with the Bank (see Note 6 to the accompanying condensed consolidated financial statements), which provide a revolving loan with a maximum borrowing amount of $50.0 million that is available until May 31, 2024 with interest at SOFR plus 1.6%. During the three months ended October 31, 2023 and 2022, we did not enter into any material derivative financial instruments for trading, speculation or other purposes that would expose us to market risk.

We maintain a substantial amount of our temporarily investable cash in certificates of deposit, a money market fund, U.S. Treasury notes and a U.S. corporate debt security (see Note 3 of the accompanying condensed consolidated financial statements). As of October 31, 2023, the weighted average number of days remaining until maturity for the certificates of deposit, U.S Treasury notes and U.S. corporate debt security was 485 days. The weighted average annual interest rate of our certificates of deposit of $105.0 million, the money market fund balance of $127.0 million, the U.S. Treasury notes face value of $95.0 million and the U.S. corporate debt security face value of $9.2 million was 5.1%. To illustrate the potential impact of changes in the overall interest rate associated with our investable cash balance at October 31, 2023 on our annual results of operations, we present the following hypothetical analysis. It assumes that our condensed consolidated balance sheet as of October 31, 2023 remains constant, and no further actions are taken to alter our existing interest rate sensitivity, including reinvestments (dollars in thousands).

With the consolidation of APC, we are subject to the effects of translating the financial statements of APC from its functional currency (Euros) into our reporting currency (U.S. dollars). The effects of translation are recognized in accumulated other comprehensive loss, which is net of tax when applicable. APC remeasures transactions and subsidiary financial statements denominated in local currencies to Euros. Gains and losses on the remeasurements are recorded in the other income, net, line of our condensed consolidated statement of earnings.

In the “Risk Factors” section of our Annual Report, we included discussion of the risks to our fixed price contracts if actual contract costs rise above the estimated amounts of such costs that support corresponding contract prices. Identified as factors that could cause contract cost overruns, project delays or other unfavorable effects on our contracts, among other circumstances and events, are delays in the scheduled deliveries of machinery and equipment ordered by us or project owners, unforeseen increases in the costs of labor, warranties, raw materials, components or equipment or the failure or inability to obtain resources when needed.

We are subject to fluctuations in prices for commodities including steel products, copper, concrete and fuel. Although we attempt to secure firm quotes from our suppliers, we generally do not hedge against increases in prices for these commodities. Commodity price risks may have an impact on our results of operations due to the fixed-price nature of many of our contracts. We attempt to include the anticipated amounts of price increases or decreases in the costs of our bids. In times of increased supply cost volatility, we may take other steps to reduce our risks. For example, we may hold quotes related to materials in our industrial construction services segment for very short periods. For major fixed price contracts in our power industry services segment, we may mitigate material cost risks by procuring the majority of the equipment and construction supplies during the early phases of a project. The profitability of our active jobs has not suffered meaningfully from the periodic global surges in non-residential construction material costs.

Our operations have been challenged by the well-publicized global supply chain disruptions. While management of the risks associated with the inability to obtain machinery, equipment and other materials when needed continues to require our best efforts, we are concerned that the supply chain uncertainties may be impacting project owners’ confidence in commencing new work which may adversely affect our expected levels of revenues until the supply chain disruptions substantially dissipate.

Evaluation of disclosure controls and procedures. Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) as of October 31, 2023. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Based on the evaluation of our disclosure controls and procedures as of October 31, 2023, our chief executive officer and chief financial officer concluded that, as of such date, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified by the SEC, and the material information related to the Company and its consolidated subsidiaries is made known to management, including the chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure in the reports.

Changes in internal controls over financial reporting. There have been no significant changes in our internal control over financial reporting (as defined in Rules 13a-15 and 15d-15 under the Exchange Act) during the fiscal quarter ended October 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.