Item 1. Business

Reorganization

ADA-ES, Inc. (“ADA”), a Colorado corporation, was incorporated in 1997. Pursuant to an Agreement and Plan of Merger ("Reorganization"), effective July 1, 2013, Advanced Emissions Solutions, Inc. (“ADES”), a Delaware company incorporated in 2011, replaced ADA as the publicly-held corporation and ADA became a wholly-owned subsidiary of ADES. Each outstanding share of ADA’s common stock automatically converted into one share of common stock of ADES and the shareholders of ADA became stockholders of ADES on a one-for-one basis, holding the same number of shares in and the same ownership percentage of ADES after the reorganization as they held in and of ADA prior to the reorganization. ADES’s Second Amended and Restated Certificate of Incorporation authorizes the issuance of 100,000,000 shares of common stock, par value per share of $0.001 and 50,000,000 shares of preferred stock, par value per share of $0.001 . ADES’s common stock became listed on the NASDAQ Capital Market under “ADES”, ADA’s previous symbol, and ADA’s stock ceased trading on the NASDAQ Capital Market on July 1, 2013. Since the Company was not able to timely file complete financial statements with the Securities and Exchange Commission, ADES's common stock was delisted from the NASDAQ Capital Market on March 30, 2015 and began trading on the OTC Pink® Marketplace - Limited Information Tier under the trading symbol "ADES". For further information on the reorganization, see Note 21 of the Consolidated Financial Statements of this Annual Report on Form 10-K. Hereinafter, this Annual Report on Form 10-K will be referred to as the "Form 10-K".

As this filing pertains to the year ended December 31, 2014 , the terms the “Company”, “we”, “us” and “our” means ADA for the periods through and including the period ended June 30, 2013 and ADES for the dates or periods after July 1, 2013. As of December 31, 2014 ADES's wholly-owned subsidiaries included:

None of ACES, ADEquity, ADA IP or ADA-RCM6 had operations in 2013 or earlier. ADA LLC ceased operations in 2012.

Subsequent to December 31, 2014 , the Company's wholly-owned subsidiaries also include ADA Analytics, LLC and ADA Analytics Israel Ltd. (collectively "ADA Analytics"). In August 2015, the Company’s management approved an action to wind down the operations of ADA Analytics. The Company intends to address the immediate United States analytics market using alternative services and capabilities. Refer to Note 9 of our Consolidated Financial Statements in Item 8 of this Form 10-K.

ADES and its subsidiaries have continued to conduct business in substantially the same manner as conducted prior to the reorganization.

Additionally, we are an investor in Clean Coal Solutions, LLC (“CCS”), Clean Coal Solutions Services, LLC ("CCSS") and RCM6, LLC ("RCM6"), whose performances significantly impact our financial position and results of operations as these investments are accounted for under the equity method of accounting. Currently, we hold equity interests of 42.50% , 50.00% , and 24.95% in CCS, CCSS, and RCM6, respectively. All of these respective equity method investments are material to our operations and their financial statements are included in Item 15 in this Form 10-K filing.

Business Purpose and Strategy

ADES serves as the holding entity for a family of companies that provide emissions solutions to customers in the coal-fired power generation, industrial boiler and cement industries. Through its subsidiaries and joint ventures, the Company is a leader in emissions control technologies and associated equipment, chemicals, and services. Our proprietary environmental

technologies enable our customers to reduce emissions of mercury and other pollutants, maximize utilization levels and improve operating efficiencies to meet the challenges of existing and pending emission control regulations.

Our major activities include:

Operating Locations

The Company has domestic and international operations where personnel are based. The domestic operations are located in Colorado and Pennsylvania. The Pennsylvania location was closed at the end of 2015, with certain wind-down activities remaining through early 2016. The international operations are not material to the Company's total revenues or long-lived assets and were closed at the end of 2015. CCS and the related operating entity CCSS have operations within 12 states across the United States.

Markets for Our Products and Services

We provide environmental control equipment, chemicals and technologies to our primary market that consists of approximately 850 coal-fired electrical generation units and approximately 600 coal-fired boilers that produce steam for industrial processes and heating.

The share of coal-fired power generation as a percentage of U.S. electricity generation is expected to continue to decrease over the coming years due to low projected natural gas prices, increasingly stringent environmental regulations, and increased deployment of renewable power generating assets. However, we believe that coal-fired power generation will remain a significant component of the U.S. power generation mix for many years given its abundance, affordability, reliability and availability as a domestic fuel source. The Energy Information Administration ("EIA") projects that coal will provide 26% of electricity generation in 2040. The primary drivers for many of our products and services are environmental laws and regulations impacting the electric power generation industry and other coal users. These regulations include the Mercury and Air Toxics Standards (“MATS”), a federal regulation that requires all of the existing fleet and all new coal-fired plants to control mercury emissions, acid gases, and particulate matter, the Maximum-Achievable Control Technology (“MACT”) standards for industrial boilers (“IBMACT”) and the cement industry, as well as various state regulations and permitting requirements for coal-fired power plants. In addition to the federal MATS rule, certain states have their own mercury rules that are similar to, or more stringent than MATS, and many plants around the country have agreed to consent decrees which require pollution controls that in some cases are more restrictive than the existing regulations. We continue to believe the MATS and MACT rules, as well as certain state regulations, create a large market for refined coal and emission control products. Additionally, the proposed, pending, and future rules relating to CO ₂ emissions, effluent discharge, coal combustion residuals, and other pollutants are driving and we expect will continue to drive future markets for which we may develop products and solutions.

In general, coal is low cost, stable, and a reliable source of domestic energy that, unlike many other forms of energy, can be easily stored in large quantities. We believe coal is critical to ensuring the U.S. has a secure and stable source of energy. With current environmental regulations, we believe it is unlikely that any new coal plants will be financed or constructed, which suggests that the average plant age in 2040 will be 66 years old. With the continued retirement of the less efficient and generally smaller coal plants switching to other fuels, and the influx of intermittent generation such as solar and wind, we believe coal-fired generation will come to be seen as a complement to the other fuel sources to provide base-load electricity to users and to support the electric grid. This belief is reflected in the Clean Power Plan recently published by the U.S. Environmental Protection Agency ("EPA"), which has been stayed by the United States Supreme Court. This dynamic will likely push coal-fired generators to increase their focus on maintaining regulatory compliance in the most efficient and cost

effective manner, while also responding to intermittent generating sources. As coal plants age and they are dispatched with more variability rather than at base-load levels as they were designed, we expect that increased support will be required to assure reliable operation and continued compliance with environmental regulations. We expect that plants and owners will require additional support as their aging workforce retires and on-site expertise is no longer as available as utilities allocate resources elsewhere in their power generation fleets.

While the future is uncertain, we expect this will continue to drive a shift in utilities' purchasing desires towards variable cost products and integrated solutions with low capital expenditure requirements and away from large capital equipment and other fixed cost solutions that are less likely to have costs recovered given the uncertain operating life of many coal plants. We also expect to see a continued trend towards outsourcing various aspects of plant operations to third party vendors and away from having integrated plant staff.

We believe it is likely that many companies that are in the U.S. coal-related businesses, such as coal mines, coal-fired power generators and coal-centric large equipment providers will struggle to adapt to the changes expected in the coming years. However, we see opportunities for companies that can offer their customers creative and cost effective solutions that help the U.S. coal-related businesses meet regulatory compliance, improve efficiency, lower costs and maintain reliability.

As of December 31, 2014 our products, services and RC technology licenses available to coal-fired electrical generators requiring solutions to assist with compliance with emissions standards, included:

Subsequent to December 31, 2014 , newly launched products, in addition to those listed above, designed for both coal-fired electrical generators and other industries requiring solutions to assist with compliance with emissions standards, include:

Additionally, as of December 31, 2011, CCS, an unconsolidated entity in which we own a 42.5% equity interest, had built and placed into service a total of 28 RC facilities designed to produce RC at coal-fired power plants. Coal-fired power plants use RC as one of a portfolio of tools to help comply with MATS and other environmental regulations. These RC facilities produce RC that qualifies for tax credits under Section 45 of the Internal Revenue Code ("IRC"), including meeting the "placed in service" requirements (hereafter referred to as "placed in service"). The law that provides for IRC Section 45 tax credits substantially expires in December 2019 for two of CCS's RC facilities placed in service in 2009 and in December 2021 for 26 RC facilities built and placed in service in 2011. Once an RC facility is in operation, CCS may enter into contracts with tax equity investors to lease or sell the RC facility, which we refer to as an "invested" RC facility. RC facilities that are producing RC but CCS has not leased or sold are referred to as retained RC facilities ("retained") where by the tax benefits may be realized by the owners of CCS. As of December 31, 2014 , 17 RC facilities were producing RC at utility sites with 12 invested and five retained. The remaining 11 RC facilities, although placed in service, were awaiting site selection or in various other stages of contract negotiation, permanent installation or beginning full-time operations. As of September 30, 2015, 17 RC facilities were producing RC at utility sites with 12 invested and five retained. A current tax equity investor has notified CCS that it will terminate the investment effective in April 2016 and CCS will seek a new tax equity investor for that RC facility. Of the remaining 11 RC facilities, four have been permanently installed and are ready to operate pending final commitments for the purchase or lease of such facilities by tax equity investors. The remaining facilities are awaiting site selection or in various other stages of contract negotiation, permanent installation or commissioning. Some of the remaining seven RC facilities are expected to produce RC in 2016. One of the invested facilities is owned by RCM6, of which the Company owns 24.95%.

Although we intend to utilize the tax credits generated by producing RC, it is also financially advantageous to lease or sell the RC facilities to tax equity investors. The tax equity investor for a particular RC facility pays the operating expenses of the RC facility and also pays CCS either an installment purchase price or lease rental fee, and in return accrues significant tax benefits, including IRC Section 45 tax credits. The Company benefits from equity income and distributions accruing through its investment in CCS. Tax equity investors, including the Company, may benefit from their investment through the realization of tax assets and credits from the production of RC. As of December 31, 2014 and 2013 , respectively, the tax credits received under Section 45 of the IRC were $6.60 and $6.59 per ton of coal produced. The value of the Section 45 tax credits are adjusted annually based on inflation adjustment factors published in the Federal Register. As of December 31, 2014 , we have received substantial tax credits and benefits from RC facilities operated for the benefit of CCS but have not yet been able to utilize tax benefits and credits from the production of RC due to our operating losses. See Note 17 to our Consolidated Financial Statements for additional information regarding our deferred taxes.

The 17 RC facilities producing RC as of December 31, 2014 are operated by our 50% owned entity, CCSS under operating and maintenance agreements with the owners or lessees of the RC facilities.

Legislation and Environmental Regulations

Federal Mercury and Air Toxic Standards (“MATS”)

On December 16, 2011, the EPA issued the final MATS rule, which took effect on April 16, 2012. In light of legal challenges to the final rules, the EPA voluntarily stayed the effectiveness of the MATS rule on July 20, 2012 pending further reconsideration of the air pollution limits for new power plants until March 28, 2013 when the EPA finalized the MATS rule. The EPA structured the MATS rule as a MACT-based hazardous pollutant regulation applicable to coal and oil-fired Electric Utility Steam Generating Units (“EGU”), that generate electricity via steam turbines, which provides for, among other provisions, control of mercury and particulate matter, and control of acid gases such as HCl and other Hazardous Air Pollutants (“HAPs”). The EPA issued a final rule for new source standards on March 28, 2013. The MACT standards are also known as National Emission Standards for Hazardous Air Pollutants ("NESHAP").

The MATS rule for existing HAP sources establishes standards for certain HAPs emitted by coal and oil fired EGUs with a capacity of 25 megawatts or greater. According to our estimates the standard sets a limit that we believe requires the capture of up to 80-90% of the mercury in the coal burned in electric power generation boilers as measured at the exhaust stack outlet for most plants.

Unless an extension was obtained, existing HAP sources were required to comply with the MATS standards by April 2015. An authorized state permitting authority has the ability to grant HAP sources up to a one year extension, on a case by case basis, if such additional time is necessary for the installation of controls. HAP sources may also request an additional year extension by obtaining an Administrative Order ("AO") from EPA. According to our estimates based on conversations with plant operators and industry estimates, we believe that MATS compliance extensions were granted for more than 400 boilers. Some of these plants have announced retirement or are switching fuel from coal to natural gas, as described above, but we believe an opportunity to license our technologies and sell our products and services remains at a significant number of coal-fired boilers. Based on EPA compliance data available in 2015, approximately 262 affected units were reporting Hg emissions, as required without an extension. We are aware of AO extensions having been granted to units. We expect that all other units still in operation after April 2016 will be required to comply with MATS emission limits and will have implemented necessary technologies to comply with the environmental regulations.

On November 25, 2014, the Supreme Court agreed to review a decision by the U.S. Court of Appeals for the District of Columbia Circuit ("DC Circuit") on April 15, 2014 to uphold MATS in a lawsuit brought by the Utility Air Regulatory Group, the National Mining Association and a group of 21 states. The Supreme Court considered whether the EPA unreasonably refused to consider costs in determining whether regulation of HAPs emitted by electric utilities is appropriate. The Supreme Court heard arguments in March 2015. On June 29, 2015, the Supreme Court ruled that the EPA must reconsider the MATS rules as it did not properly take into account the costs of the regulations before deciding to adopt them as an "appropriate and necessary" regulation of EGUs. The decision remanded the case back to the D.C. Circuit. On November 20, 2015, the EPA proposed a supplemental finding that consideration of cost does not alter the agency’s previous conclusion that it is appropriate and necessary to regulate coal- and oil-fired EGUs under section 112 of the Clean Air Act ("CAA"). On December 1, 2015, the EPA submitted the proposed supplemental finding for public comment. The proposed supplemental finding does not affect power plants’ compliance obligations or the steps that many plants have taken and continue to make to meet those obligations by installing controls and technologies to reduce toxic air emissions. On December 15, 2015 the D.C. Circuit issued a unanimous order rejecting a motion by multiple utilities and states seeking to halt the MATS program while the EPA completes its cost analysis, which is expected in April 2016. On February 23, 2016, twenty states petitioned the Supreme Court to stay MATS during this period, but no determination has yet been made.

State Mercury and Air Toxics Regulations Affecting EGUs

In addition to federal MATS rules, certain states have their own mercury rules that are similar to, or more stringent than, MATS, and power plants around the country are subject to consent decrees that require the control of acid gases and particulate matter, in addition to mercury emissions. Seventeen states have mercury-specific rules that affect more than 260 generating units.

Industrial Boilers MACT

On December 20, 2012, the EPA finalized a specific set of adjustments to the MACT-based air toxics standards originally finalized in March 2011 for industrial boilers, including mercury, particulate matter, and acid gas emission limits. Existing boilers must comply by January 31, 2016. Non major source boilers (area sources) and major source boilers that began operations on or after June 4, 2010 were required to be compliant by March 21, 2014 and January 31, 2013, respectively. An

authorized state permitting authority has the ability to grant sources up to a one-year extension, on a case by case basis, if such additional time is necessary for the installation of controls.

The EPA estimates that approximately 600 coal-fired boilers will be affected by the industrial boiler MACT (“IBMACT”), in industries such as pulp and paper.

On December 1, 2014, the EPA announced the reconsideration of the IBMACT and proposed amendments to the version published January 31, 2013, representing technical corrections and clarifications. The proposed amendments do not affect the applicability of the final rule.

Cement MACT

In addition to issuing standards covering electric power generators, the EPA has developed a MACT-based mercury emissions regulation for the Portland cement industry through amendments to the National Emission Standards for HAPs (the “Cement MACT”). The EPA published the final Cement MACT regulation on February 12, 2013 with compliance required by September 9, 2015.

An authorized state permitting authority has the ability to grant sources up to a one year extension, on a case by case basis, if such additional time is necessary for the installation of controls. The standards for new kilns apply to facilities where construction, modification, or reconstruction commenced after May 6, 2009. The Cement MACT requires, in part, cement plants to reduce 92% of mercury emissions and 83% of hydrocarbons emissions. The EPA estimated that the rule would affect 156 kilns operating as of 2013. In an analysis published in 2010, the EPA estimated that the industry average mercury emissions were 111 pounds per million tons of clinker, which is produced in the manufacture of Portland cement. The Cement MACT limits emissions to 55 pounds per million tons of clinker. The EPA identified activated carbon injection or wet scrubbers as options to meet mercury emission limits. Plants must also meet emissions limits of three parts per million for HCl. The EPA estimated that 120 existing kilns would require scrubbers to meet the proposed HCl standards and four could meet the standard using dry lime injection. The Company offers both ACI and DSI systems to help companies meet the regulation.

SO ₂ and Particulate Matter

The EPA established National Ambient Air Quality Standards ("NAAQS") that have resulted in several rules including the Cross State Air Pollution Rule ("CSAPR"), which were designed to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states.

On July 6, 2011, the EPA finalized CSAPR and on November 21, 2014, following several court actions, the EPA realigned compliance deadlines as required by the DC Circuit. Currently, CSAPR Phase 1 implementation is scheduled for 2015 and 2016, with Phase 2 beginning in 2017. Implementation is achieved through establishing state-specific emission budgets. 28 states have been identified under CSAPR to limit SO ₂ and NO _x emissions either year-round or during the summer time. Based on published emission data and announced coal plant retirements or announcements to repower plants with natural gas, we believe that most affected states will meet 2017 emissions budgets without new controls.

On August 10, 2015, the EPA finalized the NAAQS Data Requirements rule (“DDR”) that addresses the need for additional air quality data in areas that do not have sufficient monitoring required to allow the EPA to carry out the 2010 revised SO ₂ NAAQS (“2010 1-hour SO ₂ NAAQS”). The DDR directs states and tribal air agencies to characterize current air quality in areas with large SO ₂ sources (2,000 tons per year or greater). The DDR requires air agencies to establish ambient monitoring sites or conduct air quality modeling, and submit air quality data to the EPA or, establish federally enforceable emission limit(s) and provide documentation of the limit(s) and compliance to the EPA by 2017. The EPA will use this information for future designations under the 2010 1-hour SO ₂ NAAQS. Of the areas that had sufficient air quality monitoring in place from 2009-2011 to be tested against the 2010 1-hour SO ₂ NAAQS, the EPA designated 29 areas in 16 states as Non-attainment Areas. Those states submitted State Implementation Plans ("SIP") by April 4, 2015 demonstrating how the areas will meet the 2010 1-hour SO ₂ NAAQS by July 15, 2018 (5 years after the non-attainment designation). Per the agreement between the EPA and the Sierra Club and National Resources Defense Council, which was accepted as an enforceable order by the Northern District of California on March 2, 2015 to resolve litigation concerning the completion of designations, the EPA must complete designations for all remaining areas in the country in up to three additional rounds: the first, by July 2, 2016, the second by December 31, 2017, and the final round by December 31, 2020. On April 23, 2014, the EPA recognized in a memorandum regarding guidance for 1-hour SO ₂ Non-attainment Area SIP Submissions that the emission control equipment used to comply with the EGU MATS and IB and Cement MACTS regulations will concurrently reduce SO ₂ emissions. We expect that the SO ₂ NAAQS will impact several plants in affected areas that have inadequate or nonexistent SO ₂ controls installed. Some of these plants are expected to rely on DSI to meet control requirements.

In 1999, the EPA established the Regional Haze Rule ("RHR") to improve air quality in national parks and wilderness areas. States must meet requirements established in their specific Regional Haze Plan prior to 2018, with equipment typically installed by 2017, while meeting reasonable progress goals prior to that. In 2018 the state plans will be reevaluated and revised as necessary to set new progress goals and strategies to meet the goals. NO _X , SO ₂ and particulate matter all can contribute to regional haze. Some of these plants may use the Company's services to help meet the limits imposed by the rules.

Effluent Limitation Guidelines and Coal Combustion Residuals

On September 30, 2015, the EPA set the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants. The final rule requires, among other things, zero discharge for fly ash transport water, and limits on mercury, arsenic, selenium, and nitrate from flue gas desulfurization ("FGD") wastewater (also known as "legacy wastewater"). Plants must comply with limits for legacy wastewater by November 1, 2018 with a possible extension to December 31, 2023 with state approval. Although halogens are not directly regulated in the effluent guidelines, some halogens may impact the effectiveness of biological wastewater treatment systems such are often used for selenium. On December 19, 2014, the EPA issued a final rule that implemented a set of requirements for the safe disposal of coal combustion residuals ("CCRE") that included regulations of fly ash as a solid waste and not a hazardous waste. The final rule affects both existing and new CCRs, including lateral expansions of any existing unit with respect to reducing the risk of catastrophic failure, protecting groundwater, operating criteria, record keeping, inactive units, state programs, and closure. We expect that these regulations and restrictions on CCRs including fly ash and liquid effluents will generate a continuous market beginning in the 2017 through 2018 time-frame for technologies and operating approaches to reduce liquid effluents and stabilize the resulting concentrated mixtures using fly ash. The Company is evaluating whether to develop new products to help plants comply with these rules and how these rules may affect current product offerings.

Additional Legislation and Regulations

On December 15, 2009, the EPA issued an endangerment finding that triggered a Clean Air Act requirement that the agency regulate CO ₂ emissions from stationary sources such as power plants. The DC Circuit upheld the finding on June 26, 2012. As required by the Clean Air Act, on June 2, 2014, the EPA proposed rules to reduce Greenhouse Gases (“GHG”) from existing sources in states and, on October 28, 2014, a supplemental plan for Indian Country and U.S. Territories. Industry members and states have filed an extensive consolidated litigation before the DC Circuit challenging numerous aspects of EPA’s proposed GHG rules. The court ruled on June 9, 2015, that since the EPA had not yet finalized its GHG rules under Section 111(d) of the Clean Air Act, the court could not review its legality. Subsequently, on August 3, 2015, the EPA finalized rules, in the form of the Clean Power Plan, establishing guidelines for states to follow in developing plans to reduce GHG emission from existing fossil fuel-fired EGUs. The Clean Power Plan has been challenged by multiple states in the DC Circuit. On February 9, 2016 the Supreme Court stayed the Clean Power Plan, which means it will not take effect until court review is complete. The DC Circuit has scheduled oral arguments for June 2, 2016.

Under the Plan, states are required to prepare State Implementation Plans to meet state targets established based on emission reductions from affected sources. The Plan requires that the Best System of Emission Reduction (“BSER”) is employed, and establish three building blocks that include heat rate improvements at the affected plant, substituting generation from less carbon-intensive EGUs, and substituting renewable generation. The EPA expressed in the plan that the combination qualifies as the “best” system that is “adequately demonstrated” and the combination will be required to meet the state emission limits. We believe that these regulations could create an opportunity for the Company to continue to develop technologies to address the long-term needs of our customers to reduce CO ₂ emissions through technologies applied at affected sources and approaches to support plant operations within a more complex interconnected grid environment.

On March 27, 2012, the EPA proposed the first Clean Air Act standard for CO ₂ emissions from new coal and natural-gas fired power plants as a result of two separate settlements with states and environmental groups in 2010. In response to comments received on the March 27, 2012 proposal, the EPA, on September 20, 2013, proposed revised standards regarding the same new source CO ₂ emissions standards. On June 2, 2014, the EPA proposed CO ₂ emission standards for modified and reconstructed power plants. On August 3, 2015, the EPA finalized the proposed rules for newly constructed, modified, and reconstructed power plants. These standards reflect the degree of emission limitation achievable through the application of the BSER that the EPA has determined has been adequately demonstrated for each type of unit.

Segment Information

The Company is organized in four reportable segments: (1) Refined Coal ("RC"); (2) Emissions Control - Engineering and Technology Services ("EC - ETS"); (3) Emissions Control - Manufacturing ("EC - Manufacturing"); and (4) Research and Development ("R&D").

Financial information related to each of the Company's reportable segments is set forth in the Consolidated Financial Statements filed as a part of this report in Note 18 and that information is incorporated by reference here.

Our RC segment derives its earnings from equity method investments as well as royalty payment streams and other revenues related to reduced emissions of both NO _X and mercury from coals. Reduced emissions of both NO _X and mercury from the combustion of coal is necessary to comply with regulatory standards. The Company's equity method investments related to the RC segment include CCS, CCSS and RCM6. Currently, we hold equity interests of 42.5% , 50% , and 24.95% in CCS, CCSS, and RCM6, respectively.

CCS owns, leases or sells facilities used in the production of RC. The RC facilities are located at coal-fired generation stations owned by regulated utilities, cooperatives, government agencies and wholesale power generators (collectively, "Generators"). The RC produced by the RC facilities is used by the Generators as fuel in the coal-fired boilers to produce electricity. The production of RC via these RC facilities qualifies for tax credits that are available under Section 45 of the Internal Revenue Code ("IRC")("Production Tax Credits" or "PTCs"). The IRS has issued guidance regarding emissions reductions in the production of electricity by coal-fired power plants including measurement and certification criteria necessary to qualify for the Section 45 PTCs. Under the Tax Relief and Job Creation Act of 2010, the deadline for placing qualifying RC facilities into service was extended from December 31, 2009 to December 31, 2011. CCS placed 28 RC facilities into service during the applicable time periods. The value of the Section 45 PTC is adjusted annually based on inflation adjustment factors published in the Federal Register. As of December 31, 2014 , the tax credit received under Section 45 of the IRC was $6.60 per ton of coal produced.

Those RC facilities that CCS has leased or sold to tax equity investors are referred to as invested facilities ("invested"). CCS collects lease income from the lessee, if leased, or sales proceeds from the buyer if sold, of the invested RC facilities. The Company benefits from these transactions through its equity method investment in CCS. RC facilities that are producing RC but that CCS has not leased or sold are referred to as retained RC facilities ("retained"). The owners of CCS, including the Company, may benefit to the extent PTCs and other tax benefits are realized from the operation of retained RC facilities. The ability to generate PTC's expires 10 years after each RC facility was placed into service but not later than December 31, 2021. RCM6 owns a single RC facility managed by an affiliate of CCS, of which the Company owns 24.95%.

CCSS operates and maintains RC facilities under operating and maintenance agreements. CCS or the owners or lessees of the RC facilities pay CCSS, subject to certain limitations, the costs of operating and maintaining the RC facilities plus various fees. CCSS also arranges for the purchase and delivery of certain chemical additives, which include the chemicals required for our CyClean ^TM, M-Prove ^TM , M-45 ^TM and M-45-PC ^TM technologies, necessary for the production of RC under chemical agency agreements. The term of each chemical agency agreement runs concurrently with the respective RC facilities lease. CCSS is also the primary beneficiary of certain RC facilities that are VIEs and therefore consolidates such RC facilities. All net income (loss) associated with these consolidated RC facilities is allocated to the noncontrolling equity owners and therefore does not impact our equity earnings (loss) from CCSS.

CCS also pays us royalties from licensing our M-45 ^TM and M-45-PC ^TM emission control technologies to CCS ("M-45 License"). Royalties are earned based upon (i) a percentage of the per-ton, pre-tax margin of RC produced with the M-45 License that produces a valid and verifiable Section 45 tax credit, net of certain allocable operating expenses, (ii) a percentage of the Section 45 tax credits claimed, and not invested by a licensee, sublicensee, or licensee affiliate using the M-45 License, net of certain allocable operating expenses and (iii) a percentage of the revenue, net of all direct expenses, received by CCS as a direct result of CCS's exercise of the M-45 License.

The Company is an established market leader in the supply of ACI systems for the coal-fired electric industry. The injection of activated carbon into the coal combustion flue gas downstream for the purpose of absorbing mercury molecules is the most

established and accepted technology to specifically reduce mercury emissions. The Company's proprietary and highly engineered ACI systems facilitate a customer's ability to reliably and cost effectively meet regulatory emissions limits.

Demand for ACI systems remained strong in 2013 and 2014 and into the first quarter of 2015 with the majority of coal-fired utility boilers required to comply with MATS by April 2015, although a number of units have been granted extensions for compliance until April 2016. In addition, we expect that some plants that were relying on native mercury capture due to coal characteristics and benefits from other air pollution control devices already installed such as wet scrubbers will require additional controls during certain operating periods which will result in a few additional sales of ACI systems. We also expect that some industrial boilers will require ACI to meet the IBMACT mercury compliance levels. Although the MATS compliance is required as of April 2015 or 2016, many coal-fired generators will likely modify their control processes to ensure the most effective and cost efficient compliance. As such, additional ACI opportunities may emerge over the coming years.

In 2015 the Company developed and is currently selling other environmental equipment systems; such as, ADAir-Mixer ^TM and ProRak ^TM .

We also offer consulting services to assist electric power generators and others in planning and implementing strategies to meet the new and increasing government emission standards requiring reductions in SO ₂ , SO ₃ , HCl, NO _X , particulates, acid gases and mercury. This includes demonstrations of our commercial products.

In 2015 the Company developed and is currently selling other consulting and analytic services; such as, ADA® Health Check, continuous and predictive emissions monitoring systems and solutions.

Our proprietary M-Prove™ pre-combustion coal treatment technology involves the application of proprietary chemicals to coal. This technology (formerly referred to as Enhanced Coal) substantially reduces mercury emissions and also can reduce the amount of activated carbon or other sorbents, or potentially eliminate the need to use sorbents, for mercury capture at certain coal-fired power plants. We have shown that the application of M-Prove ^TM technology to Western coals, such as Powder River Basin ("PRB") and lignite, can reduce emissions of mercury by 40% to 90%, and in some cases may, as a sole treatment option, be sufficient to meet MATS compliance. One of the advantages of the M-Prove ^TM technology is that it does not rely on bromine, which is the basis of many other competing chemical sorbent additive technologies. The power industry is beginning to experience corrosion and wastewater issues in their plants that they attribute to the use of bromine to enhance the capture of mercury. We believe that demand for M-Prove ^TM technology may accelerate after the majority of plants commence operations of their mercury control systems in early 2016. In October 2012, we were awarded the first of what we believe will be a family of patents designed to protect this technology both in the US and abroad.

The Company licenses certain emissions control technologies to CCS for the production of RC. ADA’s CyClean ^TM , M-45 ^TM and M-45-PC ^TM technologies all incorporate the M-Prove ^TM additive, along with other additives, to reduce emissions of both mercury and NO _X from coal-fired boilers. ADA licensed its patented CyClean ^TM technology to CCS upon formation of the entity in 2006, for use with cyclone boilers for the life of the patents. In July 2012, ADA licensed its M-45 ^TM technology to CCS (the “M-45 License”) for as long as Section 45 tax credits are available in order to leverage CCS’s operating expertise and allow CCS the ability to provide and use either the CyClean ^TM or M-45 ^TM technology to produce RC. In the third quarter of 2012, ADA made a technological advancement in the M-45 ^TM technology that allows it to be effective in “pulverized coal” (“PC”) boilers, which improvement is included in the terms of the M-45 License. In addition to the royalty payments discussed in the RC segment above, the use of M-Prove ^TM technology in the production of RC provides valuable operating data and validates the effectiveness of the M-Prove ^TM technology in a range of coal-fired boilers. ADA expects this information will help in its sales process for the M-Prove ^TM technology.

We have deployed technologies for conditioning flue gas streams from coal-fired combustion sources. Our flue gas conditioning chemical allows existing air pollution control devices, such as electrostatic precipitators ("ESPs"), to operate more efficiently without the use of traditional SO ₃ additives, which have been shown to be detrimental to effective mercury control by partially negating the effectiveness of certain sorbents used to absorb mercury, including activated carbon. Such treatment of

the flue gas stream allows for effective collection of fly ash particles that would otherwise escape into the atmosphere. The use of the proprietary chemical blends may help existing marginally sized ESPs continue to operate effectively when applied exclusively or in combination with other chemicals such as hydrated lime, activated carbon products, or other high-resistivity materials. Our flue gas conditioning chemical is currently sold under the registered trademark RESPond®.

The Company supplies DSI systems for the electric utility industry through its subsidiary BCSI. DSI systems inject dry alkaline sorbents to control acid gases such as SO ₃ and HCl. Our DSI technology is also used to control SO ₂ , one of six criteria air pollutants. The use of DSI for SO ₃ reduction in conjunction with ACI has also been shown to enhance the capture of mercury from coal-fired boilers. While this segment was active through 2015, the Company terminated manufacturing operations through BCSI at the end of 2015 and will focus its future efforts within the DSI market on engineering and related services, similar to our current structure in within the ACI market.

Demand for these systems remained strong in 2013 and 2014 with the majority of coal-fired utility boilers required to comply with the MATS by April 2015 and a number of units granted extensions for compliance until April of 2016. DSI is used to control HCl to meet MATS and IBMACT HCl limits, to control SO ₃ for improved ACI effectiveness for mercury control, and limited SO ₂ control. DSI sales continued into 2015 to meet MATS and the IBMACT and, are expected to continue on a more limited basis into 2016 and 2017 for CSAPR and associated SO ₂ NAAQS rule, and 2017 for the Regional Haze Rule.

Beyond 2016, we plan to sell DSI systems that are manufactured through third parties rather than by us, similar to our ACI systems.

We also offer consulting services to assist the electric utility industry and others in planning and implementing strategies to meet the new and increasing government emission standards. This includes demonstrations of our commercial products.

This segment focuses on the research and development of technologies, such as those aimed at the separation, capture and control of CO ₂ emissions related to power generation, oil & gas production technologies and energy storage applications through internal funds, and contracts supported by the DOE and industry participants. The contracts with the DOE take the form of grants or cooperative agreements and are considered financial assistance awards. The agreements require us to perform the negotiated scope of work in agreed phases, which includes testing and demonstration of technologies and the deliverables required by the DOE agreements include various technical and financial reports that we submit on a prescribed schedule.

Competition

We are an established leader in the mercury control market for coal-fired electric power generators. We add significant value to our base offerings by having complementary products and services. Our expertise and experience in conducting full-scale emissions control demonstrations reflects our understanding of the application of the control technologies that customers find valuable. Our ability to provide users with performance guarantees on our equipment along with comprehensive testing services and overall compliance strategies enhances our competitive position in this market. In the RC market, we believe Chem-Mod LLC and licensees of the Chem-Mod technology are our principal competitors. In the emissions control ("EC") equipment market, we believe Norit Americas, Inc., a division of Cabot Corporation, Alstom Power, The Babcock & Wilcox Company, United Conveyor Corporation, Nol-Tec Systems, Inc. and Clyde Bergemann, Inc. are our principal competitors in the ACI market and that Nol-Tec Systems, Inc., United Conveyor Corporation, Clyde Bergemann, Inc., Nalco-Mobotec and Babcock & Wilcox are our principal competitors in the DSI market.

Competition within the RC market is based primarily on price, the number of tons of coal burned at the coal-fired power plant where the RC facilities are operating and the tax compliance facts associated with each RC facility.

Competition for ACI systems is based primarily on price, quality, performance, terms of performance guarantees and the ability to meet the requested delivery and installation schedule. In addition, certain competitors have the ability to offer their own activated carbon for use in their ACI systems, which may provide them with a competitive advantage. Similar to ACI systems,

competition for DSI systems is based primarily on price, quality, performance and the ability to meet the requested engineering, fabrication, delivery and installation schedule.

Our mercury control chemicals primarily compete against the use of activated carbon and brominated activated carbon, as well as the use of bromine applied to the coal prior to combustion. Because of a number of market and technology dynamics, there is not a definitive connection between the sale of mercury control systems and the ultimate supply of mercury control chemicals.  Thus when we are successful with a contract for the ACI equipment, it does not guarantee that we will also sell that customer M-Prove ^TM coal additives, and when a customer buys a competitors’ ACI system it does not mean that that customer is not a viable candidate for our chemicals. 

In our R&D segment, we compete for government research projects against a wide range of emissions control companies, chemical companies and research and development companies.

Patents

As of December 31, 2014 , we had 28 United States (U.S.) patents issued or allowed, an additional 19 U.S. Provisionals or applications pending and 13 international patent applications pending or filed relating to different aspects of our technology. Our existing patents generally have terms of 15 to 20 years measured from the application date, the earliest of which was in 1993 . We consider many of our patents or pending patents to be critical to the ongoing conduct of our business.

Materials and Working Capital Practices

We purchase our materials, including equipment, fabricated modules and steel, from a variety of vendors for engineered ACI systems, components and other equipment we provide. Such equipment is available from numerous sources; however, based on the system requested by the customer we may determine that some sources are not suitable. We typically subcontract the major portion of the work associated with installation of such equipment to a variety of vendors, usually located near the work site.

Similarly, we purchase materials and components from a variety of vendors for the DSI systems fabricated at BCSI facilities. To date we have typically fabricated our own DSI silos, manifolds, lances, and control panels and integrate these components at our shop or at the power plant, but in the future we will outsource these activities.

We purchase our proprietary chemicals through negotiated blending contracts that include secrecy agreements with chemical suppliers located near major customers. These arrangements minimize transportation costs while assuring continuous supply of our proprietary chemical blends. The chemicals used are readily available, and there are several chemical suppliers that can provide us with our requirements. Supply agreements are generally renewed on an annual basis.

We do not provide any extended payment terms to our customers. We typically provide equipment warranties and performance guarantees related to our EC ACI and DCI systems. See “Risk Factors” and Note 15 , in the Consolidated Financial Statements filed as a part of this Form 10-K.

Seasonality of Activities

The sale of chemicals and RC facility operation levels depend on the operations of the electric power generators to which the applicable chemicals are provided and RC facilities are located, respectively. These customers routinely schedule maintenance outages in the spring and/or fall depending upon the operation of the boilers. During the period in which an outage may occur, which may range from one week to over a month, no chemicals are used or RC produced and purchases from us and related revenues can be correspondingly reduced. The other aspects of our business are not seasonal in any material way.

Dependence on Major Customers

We depend upon our customer relationships with owners and operators of coal-fired power generation facilities, as well as general market demand for coal-fueled power generation. Our internal and external sales staff markets our technology through trade shows, mailings and direct contact with potential customers.

Through our investment in CCS we depend upon our relationships with owners and operators of coal-fired power generation facilities, including various electric utilities and tax equity investors. CCS is the exclusive licensee for purposes of producing RC for the CyClean ^TM , M-45 ^TM and M-45-PC ^TM technologies. CCS also depends on tax equity investors with significant concentration within an affiliate of GS and, as described in Item 1A, these entities could renegotiate or terminate their leases or the utilities where the RC facilities are installed could materially reduce their use of RC.

Additional information related to major customers can be found in Note 19 of the Consolidated Financial Statements within Item 8 of this Form 10-K.

Research and Development Activities

We conduct research and development directed toward the reduction of mercury emissions, DSI, RC activities, and CO ₂ capture. Certain of this research and development, and specifically related to CO ₂ capture, has been funded under contracts and/or cost reimbursement arrangements with the DOE and other third parties. Our R&D expense, net of DOE and industry cost-share partners, for R&D during the years ended December 31, 2014 , 2013 and 2012 (Restated) was $1.5 million , $3.2 million and $0.3 million , respectively. Prior to cost share reimbursements, we incurred expenses of $3.6 million , $13.1 million and $3.1 million on our own behalf on research and development activities related to further development of our technologies during 2014 , 2013 and 2012 (Restated) , respectively. We engage in these activities in order to continue to develop technologies to bring to the broader emissions control market and to expand our own offerings into other areas.

Refined Coal Data

The following table provides summary information related to the Company's investment in CCS and the related RC facilities as of December 31, 2014 and RC tons produced for the year ended December 31, 2014 :

								Operating
		# of RC Facilities			Not Operating			Invested			Retained
RC Facilities		28			11			12			5
RC tons produced (000's)								29,535			7,138

Additional information related to RC facilities is included within Item 7 of this Form 10-K.

Backlog

Backlog represents the dollar amount of revenues we expect to recognize in the future from fixed-price contracts, primarily for ACI and DSI systems as well as certain consulting service contracts that have been signed as well as those that are currently in progress. The Company includes a project in backlog when a contract is executed. Backlog amounts include anticipated revenues associated with the original contract amounts, executed change orders, and any claims that may be outstanding with customers. It does not include contracts that are in the bidding stage or have not been awarded. As a result, the Company believes the backlog figures are firm, subject to customer modifications, alterations or cancellation provisions contained in the various contracts.

Backlog may not be indicative of future operating results. Estimates of profitability could increase or decrease based on changes in direct materials, labor and subcontractor costs, and indirect costs related to contract performance, such as indirect labor, supplies, tools and repairs, and any claims with customers. Backlog is not a measure defined by generally accepted accounting principles that are followed in the United States ("GAAP" or "U.S. GAAP") and is not a measure of profitability. The Company’s method for calculating backlog may not be comparable to methodologies used by other companies.

Employees

As of December 31, 2014 we employed 231 full-time and part-time personnel, including eight ADES executives. 95 people were employed at our offices in Colorado, 131 were employed in Pennsylvania and one was employed in each of Maryland, Massachusetts, Alabama, Texas and Illinois, respectively. BCSI, our wholly owned subsidiary, employed 129 of the 131 Pennsylvania full-time and part-time personnel at our offices in Pennsylvania.

Subsequent to December 31, 2014 , there were changes in the number of employees in connection with management's alignment of the business with strategic objectives. As of December 31, 2015, the Company had 69 full-time and part-time personnel, including six ADES executives.

Copies of Reports

Our periodic and current reports are filed with the SEC pursuant to Section 13(a) of the Securities Exchange Act of 1934 and are available free of charge within 24 hours after they are filed with or furnished to the SEC at the Company’s website at www.advancedemissionssolutions.com . Alternatively, these reports can be accessed at the SEC’s website at www.sec.gov. The information contained on our web site shall not be deemed incorporated by reference in any filing under the Securities Act or the Exchange Act.

Copies of Corporate Governance Documents

The following Company corporate governance documents are available free of charge at the Company’s website at www.advancedemissionssolutions.com and such information is available in print to any stockholder who requests it by contacting the Secretary of the Company at 9135 South Ridgeline Boulevard, Suite 200, Highlands Ranch CO, 80129 .

Forward-Looking Statements Found in this Report

This Report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act, that involve risks and uncertainties. In particular such forward-looking statements are found in this Part I and under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operation” in Part II, Item 7 below. Words or phrases such as “anticipates,” “believes,” “expects,” “intends,” “plans,” “estimates,” “predicts,” the negative expressions of such words, or similar expressions are used in this Report to identify forward-looking statements, and such forward-looking statements include, but are not limited to, statements or expectations regarding:

Our expectations are based on certain assumptions, including without limitation, that:

The forward-looking statements included in this Report involve risks and uncertainties. Actual events or results could differ materially from those discussed in the forward-looking statements as a result of various factors including, but not limited to, timing of new and pending regulations and any legal challenges to or extensions of compliance dates of them; the government’s failure to promulgate regulations or appropriate funds that benefit our business; changes in laws and regulations, accounting rules, prices, economic conditions and market demand; impact of competition; availability, cost of and demand for alternative energy sources and other technologies; technical, start up and operational difficulties; failure of the RC facilities to produce coal that qualifies for tax credits; termination of or amendments to the contracts for RC facilities; decreases in the production of RC; inability to commercialize our technologies on favorable terms; our inability to ramp up our operations to effectively address recent and expected growth in our business; loss of key personnel; potential claims from any terminated employees, customers or vendors; failure to satisfy performance guarantees; availability of materials and equipment for our businesses; intellectual property infringement claims from third parties; pending litigation; elevated spending on non-recurring cash expenses, which may last longer than expected or reductions in operating costs may be less than expected; identification of additional material weaknesses or significant deficiencies; as well as other factors relating to our business, as described in our filings with the U.S. Securities and Exchange Commission (“SEC”), with particular emphasis on the risk factor disclosures contained in those filings and in Item 1A of this Report. You are cautioned not to place undue reliance on the forward-looking statements made in this Report and to consult filings we have made and will make with the SEC for additional discussion concerning risks and uncertainties that may apply to our business and the ownership of our securities. The forward-looking statements contained in this Report are presented as of the date hereof, and we disclaim any duty to update such statements unless required by law to do so.