Charah Solutions, Inc. - Annual Report: 2019 (Form 10-K)

---

---

•	our business strategy;

•	our operating cash flows, the availability of capital and our liquidity;

•	our future revenue, income and operating performance;

•	our ability to sustain and improve our utilization, revenue and margins;

•	our ability to maintain acceptable pricing for our services;

•	our future capital expenditures;

•	our ability to finance equipment, working capital and capital expenditures;

•	competition and government regulations;

•	our ability to obtain permits and governmental approvals;

•	pending legal or environmental matters or liabilities;

•	environmental hazards;

•	industrial accidents;

•	business or asset acquisitions;

•	general economic conditions;

•	credit markets;

•	our ability to successfully develop our research and technology capabilities and to implement technological developments and enhancements;

•	uncertainty regarding our future operating results; and

•	plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

---

---

---

---

---

---

•

Remediation and Compliance Services. Our remediation and compliance services offerings primarily include environmental management of landfills for coal-fired power generation facilities and of new and existing ash ponds (particularly remediation mandates). Our environmental management service offerings cover all aspects of new and existing active pond management including: clean closure, cap-in-place, and design and construction of new ponds. Additional service offerings include all aspects of the landfill development, construction, and management process. Our remediation and compliance services teams can also provide site evaluation and characterization; preliminary design and cost estimates with life-cycle analysis; hydrogeological assessments; groundwater and containment modeling; permit application and processing for expansions and greenfield sites; design engineering; construction of landfills and cap and cover systems; conversion of impoundments to landfill sites; quality assurance and quality control and documentation; engineered fills (off-site) and other related services.

•

Byproduct Sales. Our byproduct sales offerings include the recycling of recurring and contracted volumes of coal-fired power generation waste byproducts, such as bottom ash, fly ash, and gypsum byproducts. These byproducts can be used for various industrial purposes, including in the production of concrete products as a replacement for Portland cement. Our dedicated waste byproduct sales and marketing team has a national presence and works with many of the nation’s largest power generators to identify opportunities to improve each customer’s long-term position in the market for sales of coal-fired waste byproducts while providing concrete producers with the consistent fly ash sourcing they need. With a variety of different coal sources being utilized across the power generation industry, we evaluate, process, and market the different bottom ash products to achieve the highest value for a given market area.

•

Fossil Services. Our fossil services offerings focus on recurring and mission-critical management of coal ash and routine maintenance, outage services, and staffing solutions for coal-fired power generation facilities to fulfill the environmental service needs of our customers in handling their waste byproducts. Coal ash management is mission-critical to the daily operations of power plants as they generally only have on-site storage capacity for three to four days of CCR waste accumulation. These services include silo management, on-site ash transportation, landfill management, and capture and disposal of ash byproduct from coal power operations. These operations cover the management of a wide variety of combustion byproducts, including bottom ash, flue gas desulfurization gypsum disposal, Pozatec/fixated scrubber sludge disposal, and fluidized bed combustion fly ash disposal. We coordinate all aspects of the ash management operation, from processing and screening for sales to facilitating economical disposal.

•

Nuclear Services. Our nuclear services operations, which we market under the Allied Power brand name, consist of a broad platform of mission-critical professional, technical, and craft services spanning the entire asset life cycle of a nuclear power generator. Our nuclear services offerings include routine maintenance, outage services, facility maintenance, and staffing solutions for nuclear power generation facilities. We are focused on expanding these offerings to include specialty welding, valve repairs, reactor and turbine support, and specialty engineering, among other services. Additionally, our staffing services and solutions include professional, technical, and craft staffing, managed and turnkey staffing solutions and staff recruitment and oversight services. A substantial portion of our nuclear services operations is driven by scheduled nuclear maintenance outages, which are typically planned for every 12 to 24 months.

---

---

---

•

Resource Conservation and Recovery Act. RCRA Subtitle C regulates handling, transporting, and disposing of hazardous waste. RCRA Subtitle D regulates non-hazardous wastes and delegates authority to states to develop solid waste programs. In 1991, the EPA issued final regulations under RCRA Subtitle D which set forth minimum federal performance and design criteria for municipal solid waste garbage landfills. In 2015, the EPA published regulations under RCRA Subtitle D for CCRs generated by the electric utility industry. Subtitle D municipal solid waste regulations are implemented by the states, although states can impose requirements that are more stringent than the Subtitle D standards. The CCR Rule regulates the disposal of CCRs under RCRA Subtitle D of the as non-hazardous wastes, as discussed below.

•

EPA CCRs Rule. As a CCR, coal ash had previously mainly been exempted from regulation under the RCRA by the “Bevill amendment” and, therefore, was subject to state solid waste regulations. However, after a major spill at a Tennessee Valley Authority site in Tennessee in 2008, the EPA began a rulemaking process to regulate CCRs. That process ended with the publication in April 2015 of the CCR Rule to regulate the disposal of CCRs, including fly ash, bottom ash, and flue gas desulfurization products generated at coal-fired power plants. The CCR Rule, among other things, regulates CCRs as non-hazardous waste and imposes new standards for location, groundwater monitoring, and dam stability on surface impoundments and requires long-term monitoring of existing and new surface impoundments and landfill facilities. The CCR Rule also preserves an exemption for CCRs when used for beneficial purposes. In March 2018, the EPA issued proposed Phase-1 1-Part rules to reconsider certain sections of the CCR Rule. In July 2018, the EPA issued a final Phase-1 1-Part rule to modify the CCR Rule to establish the program to grant states authorization with approved CCR permit programs under the Water Infrastructure Improvements for the Nation Act (the “WIIN Act”). The Phase-1 1-Part rule also allows CCRs to be used during certain closure situations and addresses certain matters remanded to the EPA by the D.C. Circuit Court of Appeals in June 2016. The EPA intends to reconsider and propose additional regulations to address litigation decisions by courts related to CCRs.

•

WIIN Act. In December 2016, Congress passed the WIIN Act, which, among other things, establishes state primacy for enforcement of the CCR Rule. The WIIN Act directed the EPA to provide guidance to states on issuing state regulations to manage the CCR program. The EPA published the Coal Combustion Residuals State Permit Program Guidance Document (Interim Final) in August 2017. States may now submit their regulatory programs for CCRs and receive EPA approval provided they are equivalent to or more stringent than federal guidelines. As noted above, the rule finalized by the EPA in July 2018 further implements the objectives of the WIIN Act by allowing states or the EPA to incorporate flexibilities into their coal ash permit programs.

---

•

Clean Air Act. The federal Clean Air Act of 1970 and subsequent amendments, particularly the Clean Air Act Amendments of 1990 (as amended, the "CAA"), and corresponding state laws and EPA regulations (discussed below), regulate the emission of air pollutants such as SOx, NOx, particulate matter (“PM”), and ozone. The EPA finalized more stringent ambient air quality standards for fine PM in January 2013 and for ozone in October 2015, and issued final policy assessment for NOx in April 2017 and draft policy assessment for SOx in August 2017. The EPA concluded that the current primary NOx standard is adequate, but has not taken additional steps concerning the SOx standards. Utilities have been required to make changes, such as changing fuel sources, installing expensive pollution control equipment, and, in some cases, shutting down plants to meet EPA emissions limits.

•

National Ambient Air Quality Standards. The CAA requires the EPA to set National Ambient Air Quality Standards (“NAAQS”) for six pollutants considered harmful to public health and the environment (“criteria pollutants”). Areas that are not in compliance with these standards are considered “non-attainment areas.” In recent years, the EPA has adopted more stringent NAAQS for these criteria pollutants that could directly or indirectly impact coal plants through the designation of new non-attainment areas. This could prompt local changes to permitting or emissions control requirements, as prescribed by federally mandated state implementation plans that require emission source identification and emission reduction plans. Final rules may require significant investment in emissions control technologies by our customers in the electric power generation industry and could affect the demand for coal. For example, in 2015, the EPA finalized the NAAQS for ozone pollution and reduced the limit to 70 parts per billion (ppb) from the previous 75 ppb standard. The final rule was challenged in the D.C. Circuit. On April 7, 2017, the EPA advised the D.C. Circuit that it intended to reconsider the final rule, and the Court subsequently stayed the litigation pending further action by the EPA. In August 2018, the EPA ultimately decided not to revisit the rule. As a result, the D.C. Circuit lifted its stay of the 2015 ozone NAAQS rule imposing the 70 ppb ambient air quality standard while the EPA reviews the standards under an expedited review process. On October 31, 2019, the EPA published a draft policy assessment recommending that the 70 ppb ozone NAAQS be retained. The policy assessment will be followed by a proposed rule finalizing the ozone NAAQS update by October 1, 2020.

•

Cross-State Air Pollution Rule. In July 2011, the EPA adopted the Cross-State Air Pollution Rule (the “CSAPR”), a cap-and-trade type program requiring utilities to make substantial reductions in SO2 and NOx and emissions that contribute to ozone and in fine PM emissions in order to reduce interstate transport of such pollution. The CSAPR was challenged and vacated by the D.C. Circuit Court of Appeals in August 2012, but the U.S. Supreme Court reversed that decision in April 2014. The D.C. Circuit has since lifted its stay on the CSAPR and ruled in favor of the EPA on the remaining significant issues. In January 2016, the EPA filed a brief with the D.C. Circuit addressing the remaining legal challenges left undecided by the U.S. Supreme Court’s 2014 decision. Conforming with a court-ordered schedule, the EPA implemented the first phase of the CSAPR in 2015 and 2016 and the second phase in 2017. In November 2014 and January 2015, the EPA issued notices of data availability outlining emission allowance allocations for existing generating units that began operating before and after 2010. In September 2016, the EPA finalized a rule updating the CSAPR to maintain 2008 ozone emission limitations in downwind states by addressing summer time (May-September) transport of ozone pollution (the "CSPAR Update"). The CSPAR Update, which commenced in May 2017, sets stricter NOx ozone season emission budgets in 22 states and could affect up to 886 coal-fired facilities. These emission control requirements, for both NOx and SO2, can impact the quantity and quality of CCRs produced at a power plant, add to the costs of operating a power plant, and make coal a less attractive fuel alternative in the planning and building of utility power plants. On December 6, 2018, the EPA issued the CSAPR “Close-Out” Rule, a final determination that the CSAPR achieves concerning the 2008 ground-level ozone NAAQS in 20 states. Accordingly, those states will not be required to impose requirements for further reduction in transported ozone pollution. Also, the covered states do not need to submit state implementation plans that would establish additional requirements beyond the existing CSAPR Update. Several states and other entities challenged the CSPAR Close-Out Rule in the D.C. Circuit. In a September 13, 2019 ruling,

---

•

Comprehensive Environmental Response, Compensation and Liability Act. Certain environmental laws, including the Comprehensive Environmental Response, Compensation and Liability Act (the “CERCLA”) and similar state laws, impose strict, joint and several liability on responsible parties for investigation and remediation of regulated materials at contaminated sites, including our sites, customer sites, and sites to which we sent wastes, including CCRs. CCRs may contain materials such as metals that are regulated materials under these laws. Management of CCRs can give rise to liability under the CERCLA and similar laws.

•

Mercury and Air Toxics Standards for Power Plants. In February 2012, under its Mercury and Air Toxics Standards for Power Plants rule, the EPA promulgated final limits on mercury and other toxic chemicals from new and modified power plants. In June 2015, the U.S. Supreme Court ordered the EPA to undertake cost-benefit analysis when promulgating mercury and air toxics standards. In April 2016, the EPA published a supplemental finding pursuant to the U.S. Supreme Court’s directive, which is currently being challenged in the D.C. Circuit. In April 2017, the D.C. Circuit granted the EPA’s motion to stay the litigation while the EPA reconsiders its finding that the rule is “appropriate and necessary” as required under the Clean Air Act. If upheld, requirements to control mercury emissions could result in the implementation of additional technologies at power plants that could negatively affect fly ash quality.

•

GHG Emissions. Some states and regions have adopted legislation and regulatory programs to reduce GHG emissions, either directly or through mechanisms such as renewable portfolio standards for electric utilities. These programs require electric utilities to increase their use of renewable energy, such as solar and wind power. Federal GHG legislation appears unlikely in the near term. The EPA has initiated a review of rules finalized in August 2015 for GHG emissions from new and existing fossil fuel-fired electric power plants and for carbon emissions from existing sources in the power sector (the latter being known as the “Clean Power Plan”). The Clean Power Plan establishes state-specific, rate-based reduction goals for carbon emissions and calls on the power sector to reduce carbon emissions to 32% below 2005 levels by 2030. The EPA proposed rules titled the Affordable Clean Energy Rule (the “ACE Rule”) and sought comments on a framework to replace the Clean Power Plan. Under the ACE Rule, the EPA is proposing to allow efficiency improvements at existing coal plants and proposes to regulate emissions from new power plants at different levels and has taken an inside the fence approach to emissions limitations. If the proposed replacement ACE Rule is finalized by the EPA, various states’ utility companies may be encouraged to substitute electricity generation from low-emitting coal and natural gas plants and zero-emitting renewable sources for energy generated from higher-emitting coal plants. Such changes in the energy market could impact the quantity of CCRs produced by our suppliers, add to the cost of operating power plants, and make coal-fired power plants a less attractive option in the planning and commissioning of new energy generating facilities.

•

EPA Water Quality Regulations. The EPA is addressing water quality impacts from coal-fired power plants and coal mining operations. To obtain a permit for certain coal mining activities, including the construction of coal refuse areas and slurry impoundments that may result in impacts to waters of the United States, an operator may need to obtain a permit for the discharge of fill material from the Army Corps of Engineers (“ACOE”) under Section 404, as well as a corresponding permit from the state regulatory authority under Section 401 of the CWA. All permits associated with the placement of dredge or fill material subject to minimum thresholds require appropriate mitigation. Permit holders must receive explicit authorization from the ACOE before proceeding with mining activities. In September 2015, the EPA finalized new effluent limitations (the "Clean Water Rule") under the Clean Water Act for steam electric power generating facilities. The final rule requires operators of coal plants with a generating capacity over 50 megawatts to store fly ash and bottom ash in dry landfills, rather than containment ponds. Approximately 12% of coal plants will be affected, and some marginal operations may shut down rather than face the expense of complying with the Clean Water Rule. Multiple challenges to the Clean Water Rule were consolidated and are pending before the Court of Appeals for the Fifth Circuit. On February 28, 2017, President Trump issued an executive order prompting the EPA and ACOE to consider replacing the blocked Clean Water Rule. On December 11, 2018, the EPA and the ACOE proposed a new regulation to determine which waterbodies are subject to federal jurisdiction. A final rule repealing the 2015 definition of “Waters of the United States” ("WOTUS") became effective on December 23, 2019. The repeal resets a consistent, nationwide regulatory standard to the previous pre-2015 regulations. A replacement rule that redefines WOTUS to comport with the text of the CWA is expected to be finalized in 2020. More stringent regulation of coal-fired power plants and coal mining operations could increase the cost for utilities and, thus, indirectly impact the availability and cost of fly ash for our CCR activities.

---

---

---

---

---

---

---

---

•	incur indebtedness or contingent obligations;

•	pay dividends or make distributions to our stockholders;

•	repurchase or redeem our capital stock or subordinated indebtedness;

•	make investments;

•	create liens;

•	enter into sale/leaseback transactions;

•	incur restrictions on the ability of our subsidiaries to pay dividends or to make payments to us;

•	enter into transactions with our stockholders and affiliates;

•	sell and pledge assets; and

•	acquire the assets of, or merge or consolidate with, other companies or transfer all or substantially all of our assets.

---

•	requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of debt, which reduces the cash available for other business purposes;

•	limiting our ability to obtain additional financing and creating additional liens on our assets;

•	limiting our flexibility in planning for, and reacting to, changes in our business;

•	placing us at a competitive disadvantage if we are more leveraged than our competitors;

•	limiting our ability to deduct our interest expense;

•	making us more vulnerable to adverse economic and industry conditions; and

•	restricting us from making additional investments or acquisitions by limiting our aggregate debt obligations.

---

---

•	the failure of securities analysts to continue to cover our common stock or changes in financial estimates or recommendations by analysts;

•	announcements by us or our competitors of significant contracts, acquisitions, or capital commitments;

•	changes in market valuation or earnings of our competitors;

•	variations in quarterly operating results;

•	internal control failures;

•	changes in management;

•	availability of capital;

•	general economic conditions;

•	terrorist acts;

•	natural disasters and pandemics

•	legislation;

•	future sales of our common stock; and

•	investor perception of us and the power generation industry.

•	permits BCP and its respective affiliates to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

•	provides that if BCP or its respective affiliates, or any employee, partner, member, manager, officer or director of BCP or its respective affiliates who is also one of our directors or officers, becomes aware of a potential business opportunity, transaction, or other matter, they will have no duty to communicate or offer that opportunity to us.

---

•

after BCP and its affiliates no longer collectively hold more than 35% of the voting power of our common stock, providing that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (prior to such time, vacancies may also be filled by stockholders holding a majority of the outstanding shares entitled to vote);

•	after BCP and its affiliates no longer collectively hold more than 35% of the voting power of our common stock, permitting any action by stockholders to be taken only at an annual meeting or special meeting rather than by a written consent of the stockholders, subject to the rights of any series of preferred stock concerning such rights;

•	after BCP and its affiliates no longer collectively hold more than 35% of the voting power of our common stock, permitting our amended and restated certificate of incorporation and amended and restated bylaws to be amended by the affirmative vote of the holders of at least two-thirds of our then outstanding shares of stock entitled to vote thereon;

•

after BCP and its affiliates no longer collectively hold more than 35% of the voting power of our common stock, permitting special meetings of our stockholders to be called only by our board of directors pursuant to a resolution adopted by the affirmative vote of a majority of the total number of authorized directors whether or not there exist any vacancies in previously authorized directorships (prior to such time, a special meeting may also be called at the request of stockholders holding a majority of the outstanding shares entitled to vote);

•

after BCP and its affiliates no longer collectively hold more than 35% of the voting power of our common stock, requiring the affirmative vote of the holders of at least 75% in voting power of all then outstanding common stock entitled to vote generally in the election of directors, voting together as a single class, to remove any or all of the directors from office at any time, and directors will be removable only for “cause”

•	dividing our board of directors into three classes of directors, with each class serving staggered three-year terms;

•	prohibiting cumulative voting in the election of directors;

•	establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and

•	providing that the board of directors is expressly authorized to adopt, or to alter or repeal our amended and restated bylaws.

---

---

---

---

---

---

(1)	Relates to one of our joint ventures.

(2)	Adjusted EBITDA and Adjusted EBITDA margin are non-GAAP financial measures. For a definition of Adjusted EBITDA and Adjusted EBITDA margin, as well as a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”

---

•	Revenue;

•	Gross Profit;

•	Operating Income;

•	Adjusted EBITDA; and

•	Adjusted EBITDA Margin.

---

---

---

---

---

---

---

•	A revolving loan not to exceed $50.0 million (the “Revolving Loan”);

•	A term loan of $205.0 million (the “Closing Date Term Loan”); and

•	A commitment to loan up to a further $25.0 million, which expires in March 2020 (the “Delayed Draw Commitment” and the term loans funded under such Delayed Draw Commitment, the “Delayed Draw Term Loan,” together with the Closing Date Term Loan, the “Term Loan”).

---

---

(1)	We lease equipment and office facilities under non-cancellable operating leases.

(2)	Represents minimum fees required that are not contingent upon potential changes to the Maturity Date.

(3)	Contingent payments for acquisitions and the asset retirement obligation are not included in the table above because the timing of such payments is uncertain. There are no uncertain tax positions.

---

(1)	Represents non-recurring legal costs and expenses, which amounts are not representative of those that we historically incur in the ordinary course of our business. Negative amounts represent insurance recoveries related to these matters.

(2)

Represents non-recurring start-up costs associated with the start-up of Allied and our nuclear services offerings, including the setup of financial operations systems and modules, pre-contract expenses to obtain initial contracts, and the hiring of operational staff. Because these costs are associated with the initial setup of the Allied business to initiate the operations involved in our nuclear services offerings, these costs are non-recurring in the normal course of our business.

(3)	Represents SCB transaction expenses, executive severance costs, IPO-related costs, expenses associated with the Amendment to the Credit Facility and other miscellaneous items.

(4)	Adjusted EBITDA margin is a non-GAAP financial measure that represents the ratio of Adjusted EBITDA to total revenue. We use Adjusted EBITDA margin to measure the success of our businesses in managing our cost base and improving profitability.

---

---

---

---

---

---

---

---

---

††	Schedules and similar attachments have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant will furnish a supplemental copy of any omitted schedule or similar attachment to the SEC upon request.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

•	Final capping and closure involve the installation of drainage and compacted soil layers and topsoil over areas where total airspace capacity has been consumed. Asset retirement obligations are recorded on a units-of-consumption basis as airspace is consumed. The liability is based on estimates of the discounted cash flows.

•

Post closure involves the maintenance and monitoring of the structural fill sites. Generally, we are required to maintain and monitor the structural fill sites for a 30-year period. These maintenance and monitoring costs are recorded as an asset retirement obligation as airspace is consumed over the life of the structural fill sites. Post-closure obligations are recorded over the life of the structural fill sites on a units-of-consumption basis as airspace is consumed, based on estimates of the discounted cash flows associated with performing post-closure activities.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

•	A revolving loan not to exceed $50,000 (the “Revolving Loan”);

•	A term loan of $205,000 (the “Closing Date Term Loan”); and

•	A commitment to loan up to a further $25,000 in term loans, which expires in March 2020 (the “Delayed Draw Commitment” and the term loans funded under such Delayed Draw Commitment, the “Delayed Draw Term Loan,” together with the Closing Date Term Loan, the “Term Loan”).

---

---

---

---

---

---

---

---

•	Assets contributed to the multiemployer plans by one employer may be used to provide benefits to employees of other participating employers.

•	If a participating employer stops contributing to the multiemployer plans, the unfunded obligations of the multiemployer plans may be borne by the remaining participating employers.

•	If AMS chooses to stop participating in the multiemployer plans, AMS may be required to pay the multiemployer plans an amount based on the underfunded status of the multiemployer plans, referred to as a withdrawal liability.

---

---

---

---

---

---

---

---