Coal May Qualify as Refined Coal

[Third Party Communication: * * *

This is in response to your request for rulings, submitted by your authorized representative, concerning the federal income tax consequences of the transaction described below.

Investor 1 is a State B limited liability company that is classified as a corporation for U.S. federal income tax purposes. Investor 1 is a calendar year taxpayer and uses the accrual method of accounting for book and tax purposes.

Investor 2 is a State A limited liability company that is classified as a corporation for U.S federal income tax purposes. Investor 2 is a calendar year taxpayer and uses the accrual method of accounting for book and tax purposes.

Investor 3 is a State A corporation. Investor 3 is a calendar year taxpayer and uses the accrual method of accounting for book and tax purposes.

Each of Investor 4, Taxpayer and Investor 6 is an individual resident in State A.

Company A is a State A limited liability company that is classified as a corporation for U.S. federal income tax purposes. Company A is a calendar year taxpayer and uses the accrual method of accounting for book and tax purposes. Company A serves as manager of Taxpayer. Company A is a wholly-owned subsidiary of Company B, a State A limited liability company. Company B is a wholly-owned subsidiary of Company C, a State A limited liability company, and is disregarded as an entity separate from Company C for U.S. federal income tax purposes. Company C is classified as a partnership for U.S. federal income tax purposes. Company C produces refined coal that allows coal burning power plants to reduce NOx and mercury emissions.

The members of Partnership are Investor 1, Investor 2, Investor 3, Investor 4, Taxpayer, Investor 6 and Company A.

The Facility

Partnership owns a refined coal facility (the Facility) located at the Generating Station near the Site. The Generating Station consists of two coal-fired, steam-powered electric-generating units.

The Facility was originally placed in service in Year a by Company B at the Original Generating Station located near the Original Site. Subsequent to the installation and operation of the Facility at the Original Generating Station, Company B removed the Facility from operation and stored it in a secure location on the grounds of the Original Generating Station. At the request of Generator, the Facility was installed at the Generating Station on Date a.

In order for the Facility to operate at the Generating Station, Company B made certain modifications to the Facility. The cost of these improvements, together with the cost of all other capital expenditures incurred with respect to the Facility since it was placed in service, was less than four times the value of the original Facility, assuming the original Facility remains worth at least the original cost to construct.

Partnership acquired the Facility from Company B on Date b as a contribution to the capital of Taxpayer. Company D, a State A limited liability company, serves as contract operator of the Facility.

Technology

The Facility utilizes proprietary technology sublicensed from Company C to produce refined coal (the Technology). Using the Technology, Partnership treats the feedstock coal using a manufacturing process (the Process) in which two chemical additives are metered on to the feedstock coal as it is transported through the Facility on coal belts. The application rate of the chemical additives is proportional to the weight of coal, as measured by coal belt scales on each coal belt. The resulting refined coal is then deposited in the bunkers that feed the boilers. The composition of the first chemical additive varies depending on the type of boiler and rank of coal for which the Facility is being operated to produce refined coal. For circulating fluidized-bed boilers, such as the one at Original Generating Station where the Facility was placed in service, refined coal is produced using Chemical A1. For pulverized-coal boilers such as those at the Generating Station, refined coal is produced using a combination of Chemical A1 and Chemical A2. The second chemical additive is Chemical B, which will increase the fraction of mercury associated with particulates that can be removed in particulate collectors and the fraction of soluble mercury that can be removed in wet scrubbers.

Partnership anticipates that, from time to time, Generator may request that the application rate of the chemical additives be temporarily or permanently increased to assist Generator in regulatory emissions compliance or to improve plant operations. Thus, over time, the application rate for the additives may increase or decrease, but at no time will it be decreased below the application rate certified as achieving a qualified emissions reduction in the most recent certification or most recent applicable redetermination.

All of the coal that the Generating Facility burns in its boilers is low-sulfur sub-bituminous coal (including sub-bituminous coal fines) from State C, State D, State E and State F (the Source Region). Generator does not currently depend on a single mine for feedstock coal and, therefore, expects to purchase feedstock coal from a number of mines in the Source Region that provide low-sulfur sub-bituminous coal.

Testing

As part of placing the Facility in service, Company B conducted a full-scale continuous emissions monitoring system (CEMS) field test to measure the reduction in nitric oxide and nitrogen dioxide (collectively, NOx) and mercury emissions. NOx and mercury emissions were measured as required by the CEMS field testing procedures described in section 6.03(1) of Notice 2010-54 (the Notice). Emissions for both the feedstock coal and refined coal were measured under the same operating conditions, over a period of at least three hours during which the boiler operated at a steady state and at least 90 percent of full load. The Original Generating Station had no separate NOx air pollution equipment; so, NOx was measured at the stack and mercury was measured downstream of the particulate control device. The CEMS field test demonstrated the required reductions in both NOx and total mercury emissions (both determined on a lb/Btu basis) to satisfy the requirements of at least 20% NOx reduction and at least 40% mercury reduction.

At the Generating Station, Partnership intends to rely on pilot-scale combustion testing under section 6.03(2)(a) of the Notice and coal sampling laboratory analysis for redetermination testing pursuant to section 6.04(2)(b) of the Notice. Company C has engaged the Center of a prominent university (the Center) to conduct such testing using its pilot-scale combustion furnace (the Pilot Furnace). The Pilot Furnace has been extensively used to research and investigate sulfur oxide and NOx emissions and the transformation of toxic trace metals (mercury, arsenic, and lead) during the combustion of coal and other fuels or waste materials.

Partnership conducted emissions testing at the Pilot Furnace on Date c in conformance to section 6.03(2)(a) of the Notice. The tests were conducted using coal from the Source Region that is the same rank as the feedstock coal used at the Generating Station (the Tested Coal). The Center tested emissions from both the feedstock coal and the refined coal product. According to the Center, the boiler and combustion conditions of the Pilot Furnace were designed to replicate the combustion conditions of a boiler that is coal-fired and steam-producing and of a size and type commonly used in commercial operations, including full-scale boilers of the same type as those at the Generating Station. Each test at the Pilot Furnace lasted between 45 and 90 minutes. Three different add-rates of the chemical additives were tested. All three add rates tested showed emissions reductions of at least 20% for NOx and 40% for mercury compared to emissions measured from the feedstock coal. The Center's report (the Report) indicates that "it is expected that the emissions reductions reported here would be achieved at full scale by using these treatment rates during the production of refined coal." The Report, signed by a qualified individual with the Center, concluded that the Pilot Furnace testing "accurately measured the emission reductions that would be achieved" in a full-scale boiler.

If the Process is changed, unless it is solely to increase the add rate for one or both of the chemical additives, Partnership expects to repeat emissions qualification test at the Pilot Furnace (or other pilot-scale combustion furnace) in accordance with section 6.03(2)(a) of the Notice.

If there has not been a change in the Process, Partnership expects to rely on coal sampling and analysis pursuant to section 6.04(2)(b) of the Notice for ongoing redeterminations, within six months of the most recent determination or redetermination, although the precise intervals may vary (e.g. it may be only four or five months between tests).

For each 6.03(2)(a) test at the Pilot Furnace (as described below), the feedstock coal and refined coal are sampled. The feedstock coal and refined coal samples are submitted separately for laboratory analysis to determine the sulfur and mercury content of each fuel. During each period of up to six months constituting the redetermination period, samples of both feedstock coal and refined coal will be collected at the Generating Facility on a regular basis (currently expected to be daily). Partnership intends to collect all samples for redetermination from the moving coal belts, before and after the coal has passed through the Facility. Company D personnel will collect coal samples from both edges and the center of the belt using a manual sample collection device. The daily samples will be blended (manually or otherwise) into a multi-day gross sample. Two samples of approximately two pounds each will be collected (using a scoop) from each gross sample, sealed and labeled. These samples will then be sent to an independent laboratory for preparation and analysis. Standard laboratory techniques will be used to measure the sulfur and mercury content of these samples. The testing results for sulfur and mercury content of the gross samples of feedstock and refined coal collected during the redetermination period respectively will then be averaged (using a simple arithmetic mean) for comparison to the sulfur and mercury content of the coal samples collected during the test period at the Pilot Furnace (or any more recent determination that meets the requirements of section 6.03 of the Notice).

Partnership expects to rely primarily on redetermination tests using coal sampling and laboratory analysis under section 6.04(2)(b) of the Notice and to conduct pilot furnace testing under section 6.03(2)(a) of the Notice only when required (i.e., because of a change in the Process).

For purposes of section 45 of the Code, section 3.01 of Notice 2010-54 provides that the term "refined coal" means a fuel which is (i) a liquid, gaseous, or solid fuel (including feedstock coal mixed with an additive or additives) produced from coal (including lignite) or high carbon fly ash, including such fuel used as a feedstock, (ii) sold by the taxpayer with the reasonable expectation that it will be used for the purpose of producing steam, and (iii) certified by the taxpayer as resulting (when used in the production of steam) in a qualified emission reduction. Section 3.04 of the Notice provides that the term "qualified emission reduction" means, in the case of refined coal produced at a facility placed in service after December 31, 2008, a reduction of at least twenty percent (20%) of the emissions of nitrogen oxide and at least forty percent (40%) of the emissions of either sulfur dioxide or mercury released when burning the refined coal (excluding any dilution caused by materials combined or added during the production process), as compared to the emissions released when burning the feedstock coal or comparable coal predominantly available in the marketplace as of January 1, 2003.

Section 45(d)(8) of the Code generally provides that the term "refined coal production facility" means a facility which is placed in service after October 22, 2004 and before January 1, 2012.

Section 5.02 of Notice 2010-54 provides that a refined coal production facility will not be considered to have been placed in service after October 22, 2004, if more than 20 percent of the total fair market value of the facility (the cost of the new property plus the value of the used property) is attributable to property that was placed in service on or before October 22, 2004.

Section 6.01 of Notice 2010-54 generally provides that a qualified emissions reduction does not include any reduction attributable to mining processes or processes that would be treated as mining as defined in section 613(c)(2), (3), (4)(A), (4)(C), or (4)(I) of the Code if performed by the mine owner or operator. Accordingly, in determining whether a qualified emission reduction has been achieved, the emissions released when burning the refined coal must be compared to the emissions that would be released when burning the feedstock coal. Feedstock coal is the product resulting from processes that are treated as mining, including any such processes that are actually applied by a taxpayer in any part of the taxpayer's process of producing refined coal from coal.

Section 613(c)(5) of the Code describes treatment processes that are not considered as mining unless they are provided for in section 613(c)(4) or are necessary or incidental to a process provided for in section 613(c)(4). Any cleaning process, such as a process that uses ash separation, dewatering, scrubbing through a centrifugal pump, spiral concentration, gravity concentration, flotation, application of liquid hydrocarbons or alcohol to the surface of the fuel particles or to the feed slurry provided such cleaning does not change the physical or chemical structure of the coal, and drying to remove free water, provided such drying does not change the physical or chemical identity of the coal, will be considered as mining.

Section 6.03(1) of the Notice provides, in part, that emissions reduction may be determined using continuous emission monitoring system (CEMS) field testing. Section 6.03(a)(1) provides, in part, that CEMS field testing is testing that meets all the following requirements: (i) the boiler used to conduct the test is coal-fired and steam-producing and is of a size and type commonly used in commercial operations; (ii) emissions are measured using a CEMS; (iii) if EPA has promulgated a performance standard that applies at the time of the test to the pollutant emission being measured, the CEMS must conform to that standard; (iv) emissions for both the feedstock coal and the refined coal are measured at the same operating conditions and over a period of at least 3 hours during which the boiler is operating at a steady state at least 90 percent of full load; and (v) a qualified individual verifies the test results in a manner that satisfies the requirement of section 6.03(1)(b).

Section 6.03(2) of the Notice provides that methods other than CEMS field testing may be used to determine the emission reduction. The permissible methods include (a) testing using a demonstration pilot-scale combustion furnace if it establishes that the method accurately measures the emission reduction that would be achieved in a boiler described in section 6.03(1)(a)(i) of the Notice and a qualified individual verifies the test results in a manner that satisfies the requirements of section 6.03(1)(c)(i), (ii), (v) and (vi) of the Notice; and (b) a laboratory analysis of the feedstock coal and the refined coal that complies with a currently applicable EPA or ASTM standard and is permitted under section 6.03(2)(b)(i) or (ii) of the Notice.

Section 6.04(1) of the Notice provides that a taxpayer may establish that a qualified emission reduction determined under section 6.03 applies to production from a facility by a determination or redetermination that is valid at the time the production occurs. A determination or redetermination is valid for the period beginning on the date of the determination or redetermination and ending with the occurrence of the earliest of the following events: (i) the lapse of six months from the date of such determination or redetermination; (ii) a change in the source or rank of the feedstock coal that occurs after the date of such determination or redetermination; or (iii) a change in the process of producing refined coal from the feedstock coal that occurs after the date of such determination or redetermination.

Section 6.04(2) of the Notice provides that in the case of a redetermination required because of a change in the process of producing refined coal from the feedstock coal, the redetermination required under section 6.04 must use a method that meets the requirements of section 6.03. In any other case, the redetermination requirement may be satisfied by laboratory analysis establishing that (a) the sulfur or mercury content of the amount of refined coal necessary to produce an amount of useful energy has been reduced by at least 20 percent (40 percent, in the case of facilities placed in service after December 31, 2008) in comparison to the sulfur or mercury content of the amount of feedstock coal necessary to produce the same amount of useful energy, excluding any dilution caused by materials combined or added during the production process; or (b) the sulfur or mercury content of both the feedstock coal and the refined coal do not vary by more than 10 percent from the sulfur and mercury content of the feedstock coal and refined coal used in the most recent determination that meets the requirements of the Notice.

Section 6.05 of the Notice provides that the certification requirement of section 3.01(1)(c) of the Notice is satisfied with respect to fuel for which the refined coal credit is claimed only if the taxpayer attaches to its tax return on which the credit is claimed a certification that contains the following: (1) a statement that the fuel will result in a qualified emissions reduction when used in the production of steam; (2) a statement indicating whether CEMS field testing was used to determine the emissions reduction; (3) if CEMS field testing was not used to determine the emissions reduction, a description of the method used; (4) a statement that the emissions reduction was determined or redetermined within the six months preceding the production of the fuel and that there have been no changes in the source or rank of the feedstock coal used in the process of producing refined coal from feedstock coal since the emissions reduction was most recently determined or redetermined; and (5) a declaration signed by the taxpayer in the following form: "Under penalties of perjury, I declare that I have examined this certification and to the best of my knowledge and belief, it is true, correct, and complete."

Finally, section 45(d)(8) of the Code provides that a refined coal production facility must be placed in service within certain timeframes. For purposes of the refined coal credit allowable with respect to refined coal other than steel industry fuel, the facility must be placed in service after October 22, 2004 and before January 1, 2012. Section 3.07 of the Notice provides that the year in which property is placed in service is determined under the principles of section 1.46-3(d) of the regulations; i.e., when the property is placed in a condition or state of readiness and availability for a specifically assigned function. Section 5.02 of the Notice provides that a refined coal production facility will not be treated a placed in service after October 22, 2004 if more than 20 percent of the facility's total value (the cost of the new property plus the value of the used property) is attributable to property placed in service on or before October 22, 2004. The Notice also states that the IRS will not issue private letter rulings relating to when a refined coal production facility has been placed in service.

With respect to the first issue, the Process starts with several chemical additives being added to the feedstock coal prior to its combustion in a furnace. The additives provide the chemical structure that result in the reduction of emissions of nitrogen oxide and mercury during combustion. Section 6.01 of the Notice provides generally that a qualified emissions reduction does not include any reduction attributable to mining processes or processes that would be treated as mining if performed by the mine owner or operator. In the instant case, the Process is not a mining process. Further, section 3.01 of the Notice clarifies section 45(c)(7) of the Code and specifically provides that refined coal includes feedstock coal mixed with additives. Thus, additive processes that mix certain chemicals or other additives with the coal in order to achieve emissions reductions may qualify for the refined coal production tax credit. Additionally, section 3.03 of the Notice defines comparable coal as coal that is of the same rank as the feedstock coal and that has an emissions profile comparable to the emissions profile of the feedstock coal. Accordingly, we conclude that the coal produced by using the Process and Technology constitutes a "refined coal" within the meaning of section 45(c)(7) of the Code, provided that the refined coal (i) is produced from feedstock coal that is the same source region or rank as the Tested Coal and (ii) satisfies the qualified emission reduction test stated in section 45(c)(7)(B) of the Code.

With respect to the second issue, the emissions profile of the refined coal product is compared to the emissions profile of either the feedstock coal or a comparable coal predominantly available in the marketplace as of January 1, 2003. Section 3.03 of the Notice provides that a "comparable coal" is defined as coal that is of the same rank as the feedstock coal and that has an emissions profile comparable to the emissions profile of the feedstock coal. Section 6.04 of the Notice provides that a determination or redetermination of a qualified emissions reduction is valid until the occurrence of the earliest of the following events: (i) the lapse of six months from the date of such determination or redetermination; (ii) a change in the source or rank of the feedstock coal that occurs after the date of such determination or redetermination; or (iii) a change in the process of producing refined coal from the feedstock coal that occurs after the date of such determination or redetermination. Accordingly, we conclude that provided that the feedstock coals during any determination period are from the same coal source regions and of the same rank as the Tested Coal, all feedstock coal that satisfies that criteria shall be treated as feedstock coal of the same source and rank for purposes of section 6.04 of the Notice, regardless of the mines from which such feedstock coal is purchased.

With respect to the third issue, section 6.03(3) of the Notice provides that any permissible testing method provided for in the Notice can be used in emission testing for any pollutant. That is, a taxpayer can use different testing methods for each of nitrogen oxide, sulfur dioxide or mercury, provided the method used for any pollutant is a permissible method. Section 6.04(1) of the Notice provides that an emission test establishing a "qualified emission reduction" qualifies the refined coal for a six-month period provided there is no change in the process for producing the refined coal or in the source or rank of the feedstock coal. Therefore, a taxpayer must "redetermine" the emission reductions to qualify for the succeeding six-month period using one or more approved methods. In the instant case, pilot-scale combustion testing will be arranged for, and there will be no reliance on any continuous emissions monitoring system or other field testing, which is permitted under section 6.03 of the Notice. Specifically, the Center will conduct testing (including redetermination testing) at the Pilot Furnace to determine the emissions reductions associated with burning the refined coal product compared to the feedstock. For purposes of qualifying the refined coal produced at the facilities, the Center has conducted pilot-scale combustion tests at the Pilot Furnace as documented in the Report. In conducting such tests, the Center conducted tests on the feedstock, and then mixed a separate sample of the feedstock with the additives so that it could conduct tests on the refined coal product. In each of its reports, the Center reported that the test results indicated that the blend of coal and additives achieved the required emissions reductions. Based on the foregoing, we conclude that testing by the Center for qualified emissions reductions as set forth in its test reports (including interim reports) satisfies the requirements of the Notice. Qualified emissions reduction through testing by the Center at its combustion research facility or similar pilot-scale combustion testing facilities under the Notice may be relied upon.

With respect to the fourth issue, section 6.04(1)(iii) of the Notice provides that a redetermination is required after a "change in the process of producing refined coal." Section 6.04(2) of the Notice further provides that in the case of a redetermination required by reason of a change in process, any redetermination must be made using a method permitted under section 6.03 of the Notice, rather than the simplified methods of section 6.04(2)(b). We conclude that increasing the amounts of chemical additives to the feedstock coal will not be construed as a change in process requiring additional testing for qualified emissions reductions under section 6.03 of the Notice nor will it be construed as a change in process to later resume application at the rate used in the original test.

With respect to the fifth issue, it is intended that redetermination testing will occur every six months or more frequently if required pursuant to the Notice. However, the Center is not always able to issue the written report required by section 6.03(2)(a) of the Notice within the six month period. Thus, although redetermination testing is completed within the six month period, the report may be received after the six month period. Nonetheless, the Center informed the interested parties of the results of the test on the day of the tests so that it was able to take into account the results of the redetermination within the six month period. Nevertheless, the delay by the Center in issuing its report cannot be indefinite. Accordingly, we conclude that the results set forth by the Center in a redetermination test report for production may be relied upon after the date of testing even if the report is not received until after the six-month period specified in section 6.04(1)(i) of the Notice, so long as the written report is received within 90 days from the date of testing. However, the redetermination of qualified emissions reduction must occur during the earliest of the events described in section 6.04 of Notice 2010-54 regardless of the time of the actual receipt of the Center's report.

With respect to the sixth issue, section 6.04(2) of the Notice provides, in part, that in the case of a redetermination required because of a change in the process of producing refined coal from the feedstock coal, the redetermination required under section 6.04 of the Notice must use a method that meets the requirements of section 6.03 of the Notice. In any other case, the redetermination requirement may be satisfied by laboratory analysis establishing that the sulfur and mercury content of both the feedstock coal and the refined coal do not vary by more than 10 percent from the sulfur and mercury content of the feedstock coal and refined coal used in the most recent redetermination that meets the requirements of the Notice. Accordingly, we conclude the redetermination requirement of section 6.04 of the Notice may be satisfied by laboratory analysis establishing that the sulfur and mercury content of both the feedstock coal and the refined coal, on average, do not vary by more than 10 percent below the bottom of (nor more than ten percent above the top of) the range of the sulfur and mercury content of the feedstock coal and refined coal used in the most recent determination that meets the requirements of section 6.03 of the Notice.

With respect to the seventh issue, we understand that the Facility has been relocated. All of the essential components of the Facility were relocated and retained. Similarly, during the life of the Facility, it may be necessary to again relocate the facility or replace certain major components. In the event of relocation or replacement of a component, there should be no change in the placed in service date of the Facility as long as the test described in section 5.02 of the Notice has been met. Based on the foregoing, we conclude that provided the Facility was "placed in service" prior to January 1, 2012, within the meaning of section 45(d)(8) of the Code, relocation of the Facility to a different location after December 31, 2011, or replacement of part of the Facility after that date, will not result in a new placed in service date for the Facility for purposes of section 45 of the Code provided the fair market value of the used property is more than 20 percent of the Facility's total fair market value at the time of relocation or replacement.

This ruling expresses no opinion regarding any issue not specifically addressed in this ruling letter, including (1) whether any person has sold refined coal to an unrelated person, or (2) when the facility was "placed in service." In particular, we express or imply no opinion that Taxpayer has sufficient risk or rewards of the production activity to qualify as the producer of the refined coal. The Service may challenge an attempt to transfer the credit to a taxpayer who does not qualify as a producer, including transfers structured as partnerships, sales or leases that do not also transfer sufficient risks and rewards of the production activity.

No opinion is expressed whether the transaction complies with section 49 or 465 of the Code.

In accordance with the Power of Attorney on file with this office, we are sending a copy of this letter to your authorized representatives. A copy of this ruling must be attached to any income tax return to which it is relevant. Alternatively, taxpayers filing their returns electronically may satisfy this requirement by attaching a statement to their return that provides the date and control number of the letter ruling.