Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Overview

We develop, offer and implement proprietary environmental technology and market equipment and specialty chemicals to the coal-burning electric power generating industry, to the Portland cement industry and to industrial boiler operators. We have three operating segments: RC (refined coal), EC (emission control) and CC (CO ₂ capture). The RC segment includes revenues from the leasing of two RC facilities and coal sales which approximates the cost of coal acquired to demonstrate new RC facilities placed in service. The EC segment includes revenue from the supply of emissions control systems including powdered activated carbon injection systems (“ACI”), dry sorbent injection systems (“DSI”) to control SO ₂ and other acid gases and the sale of specialty chemicals, equipment and services for flue gas conditioning projects, the licensing of certain technology, consulting services related to such matters and other applications. The CC segment includes revenue from projects relating to the CO ₂ capture and control market, including projects co-funded by government agencies, such as the Department of Energy (“DOE”) and industry supported contracts.

We conduct research and development efforts in CO ₂ capture and control from coal-fired boilers. In September 2010, we signed our second significant contract related to CO ₂ capture with the DOE, which is scheduled to continue through the end of 2014. We are marketing our RC facilities through our interest in our Clean Coal joint venture with NexGen, an affiliate of NexGen Resources Corporation.

Refined Coal

Environmental Legislation and Regulations

Clean Coal’s primary opportunity is based on certain tax credits that are available under Section 45 of the Internal Revenue Code (“Section 45 tax credits”), as it was amended by the American Jobs Creation Act of 2004, the Emergency Economic Stabilization Act of 2008, the American Recovery and Reinvestment Act of 2009 for qualifying RC and the Tax Relief and Job Creation Act of 2010. In December 2009, the IRS issued the anticipated guidance as to the specifics concerning how the emissions reductions are to be measured and certified to demonstrate compliance necessary to qualify for the Section 45 tax credits. Clean Coal placed two RC facilities in service prior to January 1, 2010 and demonstrated the required emission reductions for their RC product to qualify for the Section 45 tax credits. In December 2010, the Tax Relief and Job Creation Act of 2010 extended the placed in service deadline for the Section 45 tax credits to January 1, 2012. The tax credits amount to an annually escalating $6.33 per ton (in 2011) of RC for a period of ten years.

Clean Coal

On June 29, 2010, Clean Coal executed contracts in which the two RC facilities were leased by Clean Coal’s wholly owned subsidiaries AEC-TH, LLC and AEC-NM, LLC (the “Lessors”) to GS RC Investment, LLC (the “Lessee”), with initial two and one half year terms and annual renewals that were set to expire in 2019. The two facilities are installed at two different power plants in the Midwest each of which operates two cyclone boilers burning PRB coal from Wyoming.

On November 21 and December 15, 2011, Clean Coal, the Lessors and the Lessee entered into two Exchange Agreements (each agreement related to the facility owned by each Lessor) pursuant to which the parties agreed to exchange the leased RC facilities at each power plant with newly constructed, redesigned RC facilities which resulted in termination of the

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original leases and issuance of new lease agreements (the “Exchange Transactions”). The new leases carry over many of the substantive terms and conditions of the initial leases, have initial terms that run through December 31, 2012 (the “Initial Term”) and automatically renew for annual terms through 2021.

Each lease may be terminated by the Lessee for various reasons, the most significant of which are:

In June 2010, the Lessee entered into supply agreements for each RC facility pursuant to which it continues to supply RC to the applicable power plant owner. Clean Coal Solution Services (“CCSS”), a Colorado limited liability company owned 50% by us and 50% by NexGen, will (subject to oversight by the Lessee) continue to operate and maintain the RC facilities under two Operating and Maintenance Agreements entered into with the Lessee in June 2010. CCSS also arranges for the purchase and delivery of certain chemical additives necessary for Lessee’s production of RC under two supply agreements entered into with the Lessee as part of the original transaction. The term of each supply agreement runs coincident with the leases.

We control and consolidate the results of Clean Coal in our financial statements, but do not consolidate the results of CCSS because NexGen controls the entity pursuant to the operating agreement of the entity. Historically, the utilities at which the facilities operate have used over six million tons of coal per year, which amount can vary based on several factors. The total annual contribution to our operating income will ultimately depend on the utilities’ use of coal in the generation of electricity, which use will likely fluctuate over the term of the Section 45 tax credits. In order to maintain our interest in Clean Coal, we are obligated to fund half of its operating costs and capital expenditures.

We, Clean Coal and the Lessee also entered into a technology sublicense, as amended pursuant to two amendments entered into as part of the Exchange Transactions (the “Technology Sublicense”). Pursuant to the Technology Sublicense, we licensed and Clean Coal sublicensed to the Lessee certain technology required to operate each RC facility and to produce RC. The Technology Sublicense parallels the license previously granted by us to Clean Coal and requires that we stand behind Clean Coal if it fails to perform its obligations under the sublicense, other than as a result of a default by Lessee. The Technology Sublicense contains representations and warranties customary for such agreements regarding intellectual property, and, subject to certain liability limits, requires us to indemnify the Lessee in the event of certain infringement claims by a third party. We are also obligated to actively prosecute infringement of the technology by third parties, or to cooperate with the Lessee if it does so, in which case any award would go to the Lessee and any other sublicensee who prosecutes the infringement. The annual license fee payable to Clean Coal for the sublicense is $10,000 per year, but this amount is deductible from the amount the Lessee pays in rent under the leases.

In addition, pursuant to the Exchange Transactions, we, NexGen and two entities affiliated with NexGen have provided the Lessee with new joint and several guaranties (the “CCS Guaranties”) guaranteeing all payments and performance due under the agreements described above. We also entered into a contribution agreement (the “Contribution Agreement”) with NexGen under which any party called upon to pay on a CCS Guaranty is entitled to receive contribution from the other party equal to 50% of the amount paid. The parent of Lessee provided Clean Coal with a guaranty as to the payment only of all fixed rent payments under the leases, which, although terminable at any time, cannot be terminated without the substitution of such guaranty with another guaranty on similar terms from a creditworthy guarantor

In December 2010, the Tax Relief and Job Creation Act of 2010 extended the placed in service deadline for the Section 45 tax credits to January 1, 2012. In consideration of the extension, Clean Coal built and qualified an additional 26 RC facilities using a combination of the CyClean and M-45 technologies, which met the extended placed in service date. ADA expects several of these RC facilities to begin routine operations in 2012. Once the final utility site and financing partner have been determined, it takes an average of approximately six months to obtain environmental permits for full-time operation, secure necessary approvals from state Public Utility Commissions, negotiate and complete all necessary contracts and obtain private letter rulings (“PLRs”) from the IRS in some instances where plants blend different types of coal. Since the IRS did not provide explicit guidance on blending of coal to qualify for Section 45 tax credits, some of these facilities will likely require PLRs, which may take two to three months to obtain after formal contracts are completed. Clean Coal has received $14.9 million from our first monetizer as initial deposits on 15 million tons of RC, which reserves its right to negotiate for specific RC facilities. We are currently in discussions with a number of other major financial institutions and corporate investors to reserve the right to negotiate on a number of the remaining facilities.

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We expect that the transactions for the new leases of the new RC facilities over the next year will be structured similarly to the lease transactions previously entered into for the two initial RC facilities placed in service in June of 2010. As was the case in those transactions, generally the lease of the RC facilities and the monetization of the Section 45 tax credits involve a relationship between the utility, a financial institution and Clean Coal. By leasing the RC facility and producing RC, the financial institution receives the benefit of the annually escalating per ton Section 45 tax credit ($6.33 per ton in 2011) and is able to deduct depreciation. In return it pays, and may also deduct, a fee to the utility for land use to site the RC facility and operational costs. In addition, the financial institution pays a combination of fixed and contingent rents to Clean Coal for the lease of the RC facility. In addition to the site payment, the utility receives the benefit of the resulting mercury reductions which have an estimated value of between $1.00- $4.00 per ton. In some transactions, Clean Coal may choose to operate the facility in order to directly receive the benefit of the Section 45 tax credit.

In May 2011, ADA and NexGen entered into a transaction in which Clean Coal sold an effective 15% interest of its equity, equal to approximately 15.8 units of non-voting Class B membership interests, to an affiliate of GS for $60 million in cash (the “Purchase Price”) pursuant to a Class B Unit Purchase Agreement (the “Purchase Agreement”). In conjunction with the closing of the Purchase Agreement, we, NexGen and GS entered into a Second Amended and Restated Operating Agreement for Clean Coal (the “Restated Operating Agreement”) and an Exclusive Right to Lease Agreement (the “Lease Agreement”). Pursuant to the Restated Operating Agreement, we and NexGen each exchanged 50 units of membership interests in Clean Coal for approximately 42.1 voting Class A Units in Clean Coal, representing a total of approximately 84.2% of the equity interests in Clean Coal following the transaction. ADA and NexGen each received $30 million as a result of the sale, and subsequent to the transaction with GS, NexGen paid the Company the remaining balance due of $1.8 million as payment in full of the amount owing by NexGen to maintain its interest in Clean Coal, including payment in full of all other amounts owing to us totaling $480,000 under certain previously issued “tonnage notes.”

Pursuant to the transaction with GS, we and NexGen provided GS with joint and several guarantees (the “Limited Guarantees”) guaranteeing the performance by Clean Coal of its obligation to indemnify GS against certain losses it may suffer as a result of inaccuracies or breaches of the representations and warranties made by Clean Coal in the Purchase Agreement or the Lease Agreement, or if Clean Coal breaches its covenants in the Purchase Agreement or the Lease Agreement. Clean Coal’s indemnification obligations for breaches of representations, warranties and covenants, other than for breaches of the representations involving organization, subsidiaries, capitalization and voting rights, authority and non-contravention and valid issuance, are subject to a non-recoverable deductible of $500,000 and a cap of the Purchase Price. We also entered into a contribution agreement with NexGen under which any party called upon to pay on a Limited Guaranty is entitled to receive contribution from the other party equal to 50% of the amount paid.

The rights and obligations of the parties are set forth in detail in the Restated Operating Agreement, which provides, among other related terms and conditions, that prior to April 1, 2012, Distributable Cash (as defined in the Restated Operating Agreement) will be distributable approximately 84.2% to us and NexGen as holders of the Class A Units and approximately 15.8% to GS as the holder of the Class B Units. Given the 2.5% direct interest both we and NexGen retain in subsidiaries of Clean Coal previously formed to operate any RC facilities, the effective sharing ratio of net cash generated by all expected refined coal operations is 15% to GS and 85% to us and NexGen. Beginning with distributions made after December 31, 2012, Clean Coal must distribute no less than 70% of Distributable Cash, at least annually. Within 10 days of April 1, 2012, Clean Coal must calculate a “Projected Distributable Value,” which is defined in the Restated Operating Agreement as an estimated amount equal to the net present value, using a 15% discount rate, that Clean Coal projects it will receive through the end of the term of all effective (i.e., contractually committed) RC facilities. For distributions occurring after April 1, 2012, if 15.8% of the Projected Distributable Value is equal to or greater than GS’ “Unrecovered Investment Balance” (which is the dollar amount necessary, at any given time, to return GS at least its $60 million investment, plus a 15% return thereon, taking into account all prior distributions to GS), GS is entitled to receive 15.8% of each distribution. If the “Projected Investment Value” (which is 15.8% of the Projected Distributable Value) is less than the Unrecovered Investment Balance as of the time for any given distribution, then an adjustment will be made to the distribution ratios to compensate GS for this deficiency. This adjustment is to be updated from time to time over the life of the investment, and at any time when Projected Investment Value becomes equal to or greater than GS’ Unrecovered Investment Balance, the amount payable to GS again becomes 15.8% of the distribution (or a lesser amount if amounts previously distributed have resulted in overpayments to GS). Clean Coal may make greater distributions to GS than required at any given time in order to shorten the time in which the Unrecovered Investment Balance will be reduced to $0.

In addition, the Restated Operating Agreement provides that upon the occurrence of a Liquidation Event (as defined in the Restated Operating Agreement), GS will be entitled to receive the greater of (A) a liquidation preference in an amount equal to the Unrecovered Investment Balance as of the date of such Liquidation Event (the “Liquidation Preference”) or (B) GS’ pro rata share of the proceeds from such Liquidation Event.

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Furthermore, the Restated Operating Agreement states that on or after the earlier of (i) a breach of any material provision of the Purchase Agreement or Clean Coal’s organizational documents that is not cured in accordance with the Restated Operating Agreement and that results in damages to GS of at least $10 million or (ii) the ten year anniversary of the date the last refined coal facility owned by Clean Coal or one of its subsidiaries is placed in service (but in no event later than December 31, 2021), and if the Unrecovered Investment Balance has not been reduced to zero, GS may require its Class B Units to be redeemed by Clean Coal for an amount equal to its Unrecovered Investment Balance, payable within 180 days of the notice of redemption. In addition, the Restated Operating Agreement contains provisions in regard to GS’ right to a board observer, each parties’ rights and obligations with respect to capital calls, preemptive rights, approval of certain transactions, drag-along and tag-along rights, a covenant not to compete, an obligation for us to present certain related “business opportunities” to Clean Coal for its consideration and related matters.

Pursuant to the Lease Agreement, Clean Coal granted GS the exclusive right (but not the obligation) to lease facilities that will produce up to approximately 12 million tons (+/- 10%) (the “Target Tons”) of refined coal per year on pre-established lease terms similar to those currently in effect for Clean Coal’s two existing facilities, but which are more economically favorable to Clean Coal than the rates in the present leases for the existing refined coal facilities that Clean Coal leased to another GS affiliate in June 2010. Clean Coal is required to submit a package to GS with respect to each RC facility it proposes that GS consider for leasing (being all RC facilities developed by Clean Coal until the Target Tons are met), and upon certification and acceptance of the certification for a given RC facility by GS, GS is required to pay Clean Coal, as a deposit, an agreed amount for each 1 million tons of projected annual refined coal production. Upon closing of a lease of a RC facility from Clean Coal, GS is required to pay Clean Coal an additional amount per 1 million tons of projected annual refined coal production. These payments are paid as advance rent, and actual amounts due under the leases (with true-ups) will be paid in accordance with the operative lease and related agreements, which will be based on the forms of documents that were used in the transactions for the existing RC facilities leased to the Lessee and will include guaranties by us and NexGen. The initial lease terms will be five years, with annual renewals for five successive one-year periods. If GS determines that it wishes not to lease a RC facility after it has paid the deposit, it can demand the return of the deposit paid for that RC facility, and the deposit must be paid within 30 days of the end of the quarter in which the demand is made. The amount of any deposit will earn interest from the date of demand until the deposit is paid.

In connection with the transaction, including the entry into the Lease Agreement, Clean Coal and the Lessee agreed to cancel the existing “first right of refusal” that was previously granted to the Lessee under the existing agreement to lease in connection with the leasing by the Lessee of two existing RC facilities. Under the cancelled first right of refusal the Lessee had the first right to lease RC facilities with up to 14 million tons of refined coal production per year.

In September 2011, ADA, NexGen, and GS entered into a First Amendment to the Restated Operating Agreement pursuant to which we and NexGen each transferred our 2.5% member interests in each of Clean Coal’s subsidiaries back to Clean Coal in return for an increase in our interest in Clean Coal to 42.5% from 42.1%. This restructuring of ownership interests did not change the financial relationships of the parties.

In September 2011, we successfully demonstrated a new patent-pending technology for producing RC for use at coal-fired power plants. ADA’s new technology, called “M-45”, complements and expands ADA’s market for RC beyond its patented CyClean technology licensed to Clean Coal, which is limited to cyclone boilers. During full-scale tests the M-45 technology achieved greater than 20% reduction in emissions of NOx and greater than 40% reduction in mercury emissions, thus demonstrating that this new technology also meets the standards necessary to qualify for IRS Section 45 tax credits.

In November 2011, we signed a non-binding term sheet for an exclusive license of the new M-45 RC technology to Clean Coal in order to leverage Clean Coal’s operating expertise, to place as many facilities in service before the year-end placed in service deadline and to take advantage of the other synergies that can be obtained by Clean Coal having the ability to provide and use either the CyClean or M-45 technology. With this license, Clean Coal could provide customers with both the patent-pending M-45 technology and ADA’s patented CyClean technology to produce RC that qualifies for Section 45 tax credits. This allows Clean Coal to potentially use some facilities placed in service using CyClean technology to treat larger annual volumes of coal if applied at a different plant using the M-45 technology.

We expect the license, which is subject to due diligence and negotiation and closing of definitive agreements, will provide ADA with a royalty based on a percent of operating income from future production of RC produced with the M-45 technology and prepaid royalties that included an initial refundable payment of $2 million, which was eliminated in the consolidation, paid to ADA upon signing of the term sheet with additional refundable payments of up to $8 million upon meeting certain milestones. The prepaid royalty payments are refundable via a withholding from 50% of future distributions or payments to ADA from Clean Coal if certain conditions are not satisfied.

To date, Clean Coal has installed and operated a total of 26 additional RC systems using a combination of the CyClean and M-45 technologies. We expect that each of these RC facilities satisfies the placed in service requirements from initial operations. If all planned RC systems become fully operational, after obtaining environmental permits for full-time operation and completing all necessary contracts, they could produce a total of more than 60 million tons of RC per year.

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Our RC business opportunities do not depend upon any new environmental or tax regulations. The current ten year tax credits do not require any additional approval by Congress, which provides us with a high degree of confidence that Clean Coal and the M-45 technologies will generate long-term cash flows.

ADA expects to generate pre-tax income of greater than $1.00 per ton of RC produced per year for facilities leased to others after payments to its joint venture partners of Clean Coal for the ten year life of the tax credits. From RC facilities leased to others, ADA expects revenue and earnings before interest and taxes (“EBIT”) of approximately $100 million and $50 million per year, respectively, by the end of 2012, with the potential to double the revenue and EBIT figures by the end of 2013. During 2012, new facilities are also expected to generate greater than $70 million in cash receipts from prepaid rent for Clean Coal. Clean Coal is also evaluating plans to keep as much as 20% of the RC volume to offset federal tax obligations. For the RC production that Clean Coal retains, in addition to operating costs, Clean Coal will record coal sales and costs of coal that may be significant, which will result in increased revenues (over and above the revenue increases from the monetized RC facilities) and expenses, and will likely keep margin dollars similar to levels as if the RC was not retained. As a result, we expect that ADA’s corporate tax rate will decrease to approximately 10%.

Emission Control

Many power companies recognize the urgency of the issued and pending environmental regulations, and as a result are contracting with us to evaluate mercury and acid gas control options at a number of their plants. Utilities need to know as soon as possible whether their existing EC components are sufficient to meet the new emissions standards with the installation of low capital systems such as ACI and DSI systems. If utilities need to upgrade their equipment with new large capital equipment such as fabric filters or SO ₂ scrubbers, they need to quickly begin procurement of these systems due to long required lead times. As a result we expect additional near-term ACI and DSI demonstration revenue and further bidding on related ACI and DSI equipment.

Activated Carbon Injection and Dry Sorbent Injection Systems

To date, we have obtained contracts for or are in the process of installing 50 ACI systems intended to control mercury emissions from 55 coal-fired EGU boilers. Some market demand continues in 19 states and six Canadian provinces that either have passed their own mercury control regulations or have entered agreements with power plants to reduce mercury emissions for new power plants. We remain active in the bid and proposal process and bid activity picked up in the second half of 2011 on individual and fleet wide projects due to the anticipated release of the final MATS that occurred in December. We anticipate the need for 400 to 600 ACI systems to be supplied between 2012 and 2015, which would require rapid scale-up of our production capabilities to maintain our target and present 35% market share. For an average size EGU, the ACI equipment costs are between $600,000 and $ 1 million.

In addition to the mercury control applications for ACI systems, we have also developed and are offering commercial DSI systems to inject dry alkali sorbents for control of acid gases such as SO ₃ and HCl as well as for control of the criteria pollutant SO ₂ . DSI systems, which cost approximately $2 million to $3 million for an average size EGU, provide a low CAPEX alternative to scrubbers for meeting certain provisions of the MATS and CSAPR. We conducted full-scale tests of the DSI equipment in 2010 and 2011 for the control of HCl, SO ₂ and SO ₃ on plants burning bituminous, PRB, and lignite coals. We believe several contracts for ACI and DSI systems will be awarded this year and that MATS will generate up to $300 million in sales of both ACI and DSI systems for the Company.

Enhanced Coal

Since 2004, we have been working with Arch Coal to explore certain unique characteristics of some types of coals mined by Arch Coal that allow them to be burned with lower emissions. We believe a technical breakthrough that involves the application of proprietary chemicals to coal mined by Arch Coal in the PRB likely reduces emissions of mercury and other metals when this “enhanced” PRB coal (“Enhanced Coal”) is eventually burned at power plants. As a result, on June 25, 2010, we entered into a Development and License Agreement (the “License Agreement”) with Arch Coal. Pursuant to the License Agreement, we provided Arch Coal with an exclusive, non-transferable license to use certain technology to produce Enhanced Coal by the application of ADA’s proprietary coal treatment technology to Arch Coal’s PRB mined coal. We expect that use of this Enhanced Coal will help utilities meet the mercury emissions requirements in the MATS. Pursuant to the License Agreement, we are providing development services to Arch Coal aimed at applying the technology to the PRB coal. In addition, if we develop improvements to the technology that are related to the reduction of certain emissions from the burning of PRB coal, that technology will either be included in the license at no additional cost, or, under certain circumstances, we will negotiate with Arch Coal to determine if Arch Coal wants to

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use the additional improvements. We retain all right, title and interest, including all intellectual property rights, in and to any technology we license to Arch Coal. The initial demonstration of coal treated at the mine and shipped by rail to a power plant produced promising results.

In consideration for the development work and the license to Arch Coal, Arch Coal paid us an initial, non-refundable license and development fee in cash totaling $2 million in June 2010 and we recognized $1.3 million as revenue in 2011 and $.7 million in 2010. Under the License Agreement, we are entitled to royalties of as much as $1 per ton of a portion of the premium for Enhanced Coal sold by Arch Coal, depending upon the successful implementation of the technology and the premium Arch Coal is able to charge on future sales of the Enhanced Coal product. Any royalty ultimately payable under the License Agreement will first be subject to credit to Arch Coal of an amount equal to the initial license fee, other development and operational costs paid by Arch Coal plus a rate of return on such payments.

We believe the Enhanced Coal product may provide a $1 to $4 per ton of coal benefit to power plants. The MATS will likely create a market for reduction in mercury emissions for a significant percentage of the greater than 100 million tons per year of PRB coal mined by Arch Coal. Because of our focus on placing in service additional RC facilities prior to the end of 2011, we decided to delay additional demonstrations of our Enhanced Coal product. We expect to resume these tests in 2012, which is expected to provide sufficient time to further develop the technology and grow this business as the national mercury control market expands through 2015.

As a part of entering into the License Agreement we agreed to negotiate and enter into a Supply Agreement under which Arch Coal will purchase the additives described in the License Agreement exclusively from us, and we will supply Arch Coal with the additives it needs. We expect to finalize the terms of the Supply Agreement in 2012.

CO ₂ Capture

In addition to our two key growth areas, RC and emission control, we continue to demonstrate our position as a premier developer of innovative clean energy technologies. We expect that CO ₂ capture technologies will be required to control CO ₂ emissions from coal-fired power plants in the future as a result of the impact of CO ₂ emissions on climate change. A number of permits for new coal-fired plants were rejected by various state officials in response to protests by environmental groups. We see this as an opportunity and continue to develop technologies to address the long-term needs of our customers to reduce CO ₂ from their existing and new plants.

On December 15, 2009, 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. Industry and states have filed an extensive consolidated litigation before the U.S. Court of Appeals for the District of Columbia Circuit challenging numerous aspects of EPA’s Greenhouse Gas (“GHG”) rules. The U.S. Court of Appeals for the D.C. Circuit is considering arguments regarding EPA’s guidance memo on the timing of GHG regulations, such as when GHGs become a “regulated pollutant” under the Clean Air Act and thus New Source Review (“NSR”) and Prevention of Significant Deterioration (“PSD”) regulations apply.

EPA anticipates proposing its first new source performance standards (“NSPS”) for CO ₂ emissions from new power plants within the next few months as a result of a separate settlement with states and environmental groups in 2010.

DOE is funding CO ₂ control projects and in September 2010, we signed a contract with DOE to continue development of clean coal technology to capture CO ₂ from coal-fired power plants and other industrial sources of CO ₂ emissions. The agreements with the DOE provide that any inventions we create as a result of the work become our property and we retain the rights to commercialize any products we develop under the contracts. We participated in two such agreements in 2011 pursuant to which we are researching and developing a novel process to capture CO ₂ from coal-fired power plants.

In 2010 we began the first field tests of our CO ₂ control technology on a $3.8 million program co-funded by DOE, as well as several major forward-thinking utility companies. The initial results at a plant confirmed the promising performance we had demonstrated in our laboratory. The pilot plant was moved to another plant for additional testing. Once captured, the CO ₂ could be either stored underground (sequestration) or beneficially used in processes such as enhanced oil recovery. This technology appears to offer potential cost and energy advantages over competing liquid-solvent-based technologies.

In October 2010, we began work on a second major CO ₂ project, which is expected to run for a total of 51 months to scale-up the technology to the one-megawatt level, which is a key step in the technology development process. We are the prime contractor for the approximately $19 million project administered by DOE’s National Energy Technology Laboratory which is providing $15 million of the funding. The project provides funding to advance our commercialization plan for regenerable solid-sorbent technology, which is designed to capture CO ₂ generated by coal-fired power plants.

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We have completed the first budget period of the 51-month DOE project. Continued project funding is dependent on approval of the DOE and our industry partners. We anticipate the DOE will make a positive decision about continuation within the next few months.

We anticipate that DOE funded CO ₂ programs will continue to represent an important component of the revenue stream of the Company over the next several years as we position ourselves for the market growth for ACI systems, enhanced coal additives and related technology with Arch Coal and other technologies for emissions control.

Results of Operations – 2011 versus 2010

Revenues totaled $53.3 million for 2011 versus $22.3 million in 2010, representing an increase of 139%. The change is due primarily to revenues from operations at the RC facilities we leased to a third party and coal sales for new RC placed in service facilities plus a 49% increase in our CC segment revenues. We expect overall revenues for 2012 to be significantly higher than those reported for 2011.

Cost of revenues increased by $20.3 million or 236% in 2011 from 2010 primarily as a result of costs of coal incurred related to demonstration and testing by Clean Coal of new RC facilities. In addition, costs increased in the CC segment due to the increased activity in this segment and in the EC segment due to the hiring of additional staff required to meet expected growth in this segment. Gross margins were 46% for the year compared to 61% in 2010. The decrease primarily reflects such increased costs. For the near term, we expect the RC segment to represent an increasing source of revenues, for which the anticipated gross margins are higher than our EC and CC segments. As a result, we expect the gross margin for fiscal year 2012 to be higher than the overall margin realized in 2011.

Refined Coal

Revenues in our RC segment totaled $40.3 million in 2011 compared to $10.4 million in 2010, representing an increase of 288%. The two operating RC facilities were placed into routine operations during the second quarter of 2010 and were in operation throughout 2011. In addition to recognition of rental income totaling $20.1 million from the two operating facilities, the current year includes sales of RC totaling $20 million as a result of demonstrating and placing additional RC facilities into service. We expect our quarterly revenues to continue to fluctuate based on seasonal variations in electricity demand as well as planned and unplanned outages required by the power plants for equipment repair and maintenance. On an ongoing basis, we expect the two RC facilities to process approximately 6 million tons of RC annually, qualifying for the present $6.33 per ton Section 45 tax credit through 2021.

Cost of revenues for the RC segment increased by $18.8 million or 1303% for 2011 from 2010. Costs increased in 2011 due primarily to the cost of coal acquired to test new RC facilities which costs approximate the revenues realized on its sale noted above, due to the RC facilities being in operation for a full year, and an increase in activities undertaken to place additional facilities into service. We expect future RC margins irrespective of coal purchases and sales to be at a level near 90%.

RC segment profits increased by $10.1 million or 129% for 2011 compared to 2010 as the two facilities were leased for the full year in 2011 and placed in routine operation in the middle of 2010. These amounts are prior to the allocation of such profits to the non-controlling interest of Clean Coal.

Emission Control

Revenues in our EC segment totaled $10 million in 2011 compared to $9.8 million in 2010, representing an increase of 1%. The amounts reported for 2011 and 2010 excludes the work ADA has conducted for Clean Coal, as further described below, which was eliminated in our consolidation. Revenues from the EC segment for the year ended December 31, 2011 were comprised of sales of ACI systems and services (42%), flue gas chemicals and services (9%) and other services (49%), compared to 56%, 6%, and 38%, respectively, in 2010. For the near term, we expect the consulting services in our EC segment to increase as a percentage of EC revenues as the industry seeks to analyze and evaluate the MATS. We expect our EC segment revenues related to ACI systems to start growing in 2012 when we expect utilities, cement plants and industrial boilers to start reacting to the MATS and other MACT regulations. We expect overall gross margin dollars for the EC segment for 2012 to be higher than amounts achieved in 2011 due to increased equipment sales and consulting activity.

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Our consulting revenues increased $1.3 million during 2011 compared to 2010 as a result of continued demonstrations and other work related to recent changes with the MATS and included revenues totaling $1.3 million from our Arch Coal non-refundable license. Our consulting revenues contributed $4.9 million during 2011 and we expect our consulting revenue to increase for the next year as several customers are seeking advice on how best to comply with the MATS.

As of December 31, 2011, we had contracts in progress for work related to our EC segment totaling $736,000 which we expect to recognize as revenue in 2012. Our ACI systems revenues totaled $4.1 million for 2011, representing a decrease of 25% compared to 2010. In the EC segment, we performed work related to RC systems provided to Clean Coal valued at $8.3 million and $3.7 million for the years ended December 31, 2011 and 2010, respectively, which would otherwise be recognized as revenue but was eliminated in the consolidation of Clean Coal. The amounts for 2010 include our participation in the construction and installation of the initial RC facilities. In 2011, Clean Coal utilized a number of third-party resources to construct and install the new RC facilities. However, we provided services toward the construction and installation of 26 facilities in 2011 as compared to 2 facilities in 2010.

Cost of revenues for the EC segment increased by $732,000 or 12% in 2011 from 2010, primarily as a result of increased costs related to our ACI systems activities including hiring additional staff required for expected growth. Gross margin for the EC segment was 31% for 2011 compared to 38% for 2010. The decrease in gross margin from the prior year is primarily a result of the increase in costs related to our ACI systems.

EC segment profits decreased by $764,000 or 36% for 2011 compared to 2010. The decrease was primarily a result of costs associated with hiring additional staff required for expected growth in future ACI systems sales.

CO ₂ Capture

Revenues in our CC segment totaled $3.1 million in 2011 compared to $2.1 million in 2010 representing an increase of 49%. We had outstanding DOE contracts, including anticipated industry cost share in progress totaling $15.7 million as of December 31, 2011. We expect to recognize approximately $5.6 million from these contracts in 2012 including participation by other industry partners. As discussed above, back on September 30, 2010 we signed a contract on a DOE project totaling approximately $19 million (including expected contributions by other industry partners).

Cost of revenues for the CC segment increased by $858,000 or 80% for 2011 from 2010, primarily from increased activities related to our development of CO ₂ capture technology. Gross margin for this segment was 38% in 2011 compared to 49% in 2010. The decrease in gross margin from 2011 to 2010 is due primarily to greater use of subcontractors for which our margins are lower under these projects. Lower cost share participation from third parties also contributed to higher costs and lower margins. We expect overall gross margins for the CC segment for 2012 to be lower than the levels achieved in 2011, due to our likely share of costs and the mixture of direct costs (labor versus equipment) associated with this segment.

CC segment profits decreased by $654,000 or 73% for 2011 compared to 2010. As discussed above, the decrease was primarily the result of greater use of subcontractors and lower cost share participation by others.

Our contracts with the government are subject to audit by the federal government, which could result in adjustments to previously recognized revenue. Our historical experience with these audits has not resulted in significant adverse adjustments to amounts previously received; however the audits for the years 2004 and later have not been finalized. Revenues recognized from 2005 through 2011 that are subject to government audit totaled approximately $32 million. In addition, we had $15.7 million of remaining unearned amounts under contracts subject to audit as of December 31, 2011. We believe, however, that we have complied with all requirements of the contracts and future adjustments, if any, will likely not be material. In addition, the federal government must appropriate funds on an annual basis to support DOE contracts, and funding is always subject to unknown and uncontrollable contingencies.

Other Items

General and administrative expenses decreased by $15.3 million or 47% to $17.5 million in 2011. Legal costs decreased $20.4 million or 83% in 2011 primarily due to a decrease in non-routine expenses associated with litigation and settlements which totaled $24.5 million in 2010. We believe our legal expenses have now returned to more routine levels. This decrease was offset by increases in compensation costs and other general and administrative costs totaling $1.5 million and $3.6 million, respectively, from 2010 which are primarily due to a 46% increase in staff in anticipation of increased business. We expect general and administrative expenses to increase as we continue to add additional resources to prepare for increased business opportunities over that time. We expect general and administrative expenses to be approximately $4 million per quarter for ADA and as much as $1 million per quarter for CCS in 2012.

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We incur research and development (“R&D”) expenses not only on direct activities that we conduct but also by sharing a portion of the costs in the government and industry programs in which we participate. Total R&D expense increased by $1.4 million or 151% in 2011 compared to 2010 as a result of increases in RC and CC activities. We incurred $343,000 for direct cost share for R&D under DOE related contracts in 2011. We had no significant direct cost share for R&D under DOE related contracts in 2010. The increase in total R&D is related to preparing for growth in the delivery of our ACI systems, as well as our RC activities. Future consolidated research and development expenses, except for those anticipated to be funded by the DOE contracts and others that may be awarded, are expected to be higher in 2012 compared to 2011. We continue to anticipate that our future R&D expenses will grow in direct proportion to DOE funded CO ₂ work we perform for the next several years and other technology development we choose to pursue.

We had net other income including interest of $2.2 million in 2011 compared to $2.5 million in 2010 related primarily to interest on notes receivable and other amounts received from NexGen. We had interest expense of $1.6 million in 2011 related to the line of credit and deferred gain for income tax purposes on the Clean Coal lease transactions. There was $16,000 in interest expense in 2010. We recognized $42 million in expenses in 2011 related to the Norit matter, and a $20 million gain from the settlement with Carbon Solutions/ECP as discussed below. We recognized a net $6.1 million gain in 2010 related to the settlement with our damage claim against Calgon Carbon Corporation (“Calgon”) also as discussed below.

In November 2011, an Indemnity Settlement Agreement was entered into whereby ADA agreed to settle certain indemnity obligations asserted against ADA and relinquished all of its interest in the Carbon Solutions joint venture with ECP. The interest in Carbon Solutions was accounted for under the equity method of accounting and considerable losses had been recorded since its inception in 2008. We recorded the transactions resulting from the Indemnity Settlement Agreement for the satisfaction of the indemnity obligations and the relinquishment of ADA’s interest which resulted in a gain of $20 million which is included other income (loss) in the consolidated statements of operations.

ADA’s equity in the net loss of Carbon Solutions for 2011 and 2010 totaled $7.2 million and $8.2 million, respectively and is included in other income (expense) in the consolidated statement of operations. The amount is reported net of our equity in the net income of CCSS which amounted to $189,000 and $118,000 for 2011 and 2010, respectively.

The income tax provisions for 2011 and 2010 represent an effective tax benefit rate of approximately 53% and 42%, respectively, for the years ended December 31, 2011 and 2010. No unrecognized tax benefits were recorded as of December 31, 2011. The primary jurisdictions in which we file income tax returns are the U.S. federal government and State of Colorado. We are no longer subject to U.S. federal examinations by tax authorities for years before 2008 and Colorado state examinations for years before 2007. Our income tax rate does not include any material amount of Section 45 tax credits from Clean Coal as those tax benefits will primarily be realized by the Lessee under the RC facilities’ leases.

The net operating loss from continuing operations before income tax benefit and non-controlling interest was $25.2 million in 2011 compared to a net operating loss of $20.4 million in 2010. The net operating loss is due in large part to the costs associated with our settlement of litigation involving Norit and our equity in the losses incurred by Carbon Solutions.

Results of Operations – 2010 versus 2009

Revenues totaled $22.3 million for 2010 versus $20.1 million in 2009, representing an increase of 11%. The change is due primarily to initiation of revenues from operations at the RC facilities we leased to a third party offset by the decrease in our EC segment revenues.

Cost of revenues decreased by $5.3 million or 38% in 2010 from 2009 primarily as a result of decreased revenues in our EC segment and lower RC segment costs described below. Gross margin was 61% for the year compared to 31% in 2009. The increase primarily reflects the increased RC margins and revenues as described below.

Refined Coal

Revenues in our RC segment totaled $10.4 million in 2010 versus $2.6 million in 2009, representing an increase of 301%, as the leased RC facilities initiated routine operations. As discussed above, in June 2010 we leased the two RC facilities and earn related rent revenues, which began in July 2010.

Cost of revenues for the RC segment decreased by $1.9 million or 57% for 2010 from 2009, primarily due to the two RC facilities ramping up production levels in the fourth quarter of 2010. In 2009, we recorded the sales of RC which were made essentially on a cost basis with no margin.

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RC segment profits increased by $9.2 million or 697% for 2010 compared to 2009 as the two facilities were leased and placed in routine operation in the middle of 2010.

Emission Control

Revenues in our EC segment totaled $9.8 million in 2010 versus $15.9 million in 2009, representing a decrease of 38%. The amounts reported for 2010 and 2009 excludes the work ADA conducted for Clean Coal, as further described below, which was eliminated in our consolidation. Revenues from the EC segment for the year ended December 31, 2010 were comprised of sales of ACI systems and services (56%), flue gas chemicals and services (6%) and other services (38%), compared to 66%, 2%, and 32%, respectively, in 2009.

Our consulting revenues decreased $1.3 million during 2010 compared to 2009 as we completed nearly all of our mercury control demonstrations and analysis. Such decline is offset by our Arch Coal non-refundable license revenue. Our consulting revenues contributed $3.6 million during 2010.

As of December 31, 2010, we had contracts in progress for work related to our EC segment totaling approximately $2.9 million. Our ACI systems revenues totaled $5.5 million for 2010, representing a decrease of 48% compared to 2009. In the EC segment, we performed work related to RC systems provided to Clean Coal valued at $3.7 million and $1.3 million for the years ended December 31, 2010 and 2009, respectively, which would otherwise be recognized as revenue but was eliminated in the consolidation of Clean Coal.

Cost of revenues for the EC segment decreased by $3.4 million or 36% in 2010 from 2009, primarily as a result of the decreased revenue-generating activities from our ACI system sales. Gross margins for this segment were 38% in 2010 compared to 40% for 2009. The decrease in gross margins from the prior year is primarily a result of the impact of our consulting and ACI system margins.

EC segment profits decreased by $3.2 million or 60% for 2010 compared to 2009. The decrease was primarily a result of decreased ACI systems sales.

CO ₂ Capture

Revenues in our CC segment totaled $2.1 million versus $1.5 million for 2009 representing an increase of 36%. As discussed above, on September 30, 2010 we signed a contract on a DOE project totaling approximately $19 million (including expected contributions by other industry partners) with work ramping up in the fourth quarter of 2010.

Cost of revenues for the CC segment increased by $97,000 or 10% for 2010 from 2009, primarily from increased activities related to our development of CO ₂ capture technology. Gross margins for this segment were 49% for 2010 compared to 37% for 2009. The increase in gross margins from 2010 to 2009 is due primarily to the increased work being performed under these projects.

CC segment profits increased by $546,000 or 156% for 2010 compared to 2009. The increase was primarily the result of increased activities related to our development of CO ₂ capture technology, which ramped up significantly in 2010.

Other Items

General and administrative expenses increased by $16 million or 96% to $32.8 million in 2010. The dollar increase for 2010 resulted primarily from legal costs related to our legal proceedings with Norit and Calgon, which comprised approximately 75% of the overall general and administrative expense for 2010.

We incur R&D expenses not only on direct activities we conduct but also by sharing a portion of the costs in the government and industry programs in which we participate. Total R&D expense increased by $202,000 or 28% in 2010 compared to 2009 as a result of increases in RC and CC activities. We had no significant direct cost share for R&D under DOE related contracts in either 2010 or 2009. The increase in total R&D is related to preparing for growth in the delivery of our ACI systems, as well as our RC activities.

We had net interest and other income of $8.6 million in 2010 compared to $34,000 for 2009. In December 2010, we accepted a $7.2 million payment (recognized a net of $6.1 million after payment of certain contingent legal fees) and recognized income related to the settlement of our damage claim against Calgon. In addition, during the second quarter of 2010, we recognized approximately $1.8 million related to the notes payable delivered by NexGen, by which NexGen paid us as a portion of the amounts required to maintain its interest in Clean Coal. Such payments were recorded as other income. During the second half of 2010, we recognized approximately $200,000 in interest and other income related to the notes receivable and other amounts due from NexGen.

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The income tax provisions for 2010 and 2009 represent an effective tax rate benefit of approximately 42% and 37%, respectively, for the years ended December 31, 2010 and 2009. No unrecognized tax benefits were recorded as of December 31, 2010. Our income tax rate does not include any material amount of Section 45 tax credits from Clean Coal as those tax benefits will primarily be realized by the Lessee under the RC facilities’ leases.

In June 2009, our partner in the Carbon Solutions joint venture, ECP, converted a portion of its preferred equity contributions in Carbon Solutions to ordinary capital contributions thereby reducing our ownership interest below 50%. Accordingly, we deconsolidated Carbon Solutions in June 2009 as we no longer held a controlling interest and began to account for our investment in Carbon Solutions under the equity method of accounting. Additional preferred equity contributions were converted and common equity contributions were made by ECP since that time and our interest in Carbon Solutions decreased to 25.9% as of December 31, 2010. Our net investment of $13.6 million as of December 31, 2010 in Carbon Solutions was accounted for under the equity method of accounting. Accordingly, our equity in the net loss of Carbon Solutions for the year ended December 31, 2010 is recognized in other income (expense) in the consolidated statement of operations and our investment in Carbon Solutions was reduced by our respective share of such loss. For 2010, we recorded a loss of $8.0 million, which represents our share of Carbon Solution’s net loss for the year. The amount is reported net of our equity in the net income of CCSS which amounted to $118,000 for the year.

The net operating loss from continuing operations attributable to ADA was $20.4 million in 2010 compared to a net operating loss of $15 million in 2009. The net operating loss is due in large part to the costs associated with our litigation matters involving Norit and Calgon and the losses incurred by Carbon Solutions. We would have a net income after tax of approximately $5.1 million or $0.69 per share for the year excluding the non-routine legal expenses related to the Calgon and Norit matters and disregarding the non-cash loss from Carbon Solutions.