PLR 201128005: IRS approves refined coal treatment and emissions testing methods

Plain-English summary

A partnership asked whether coal treated with chemical additives would qualify as refined coal for the federal refined coal production credit. It also asked whether pilot-scale combustion testing and later laboratory analysis could establish the required emissions reductions, whether coal from specified seams and ranks could be treated as the same source, and how to satisfy later redetermination requirements. The IRS ruled favorably on all four questions, subject to the stated feedstock, emissions, testing, and notice conditions. The ruling did not decide who was the producer for another provision or whether the facility had been placed in service before the relevant date.

Ruling snapshot

• Question: Could the taxpayer qualify its additive-treated coal as refined coal and use the proposed testing and redetermination methods for the § 45 credit?
• Outcome: approved
• Key authorities: IRC §§ 45(a), 45(c)(7), 45(d)(8), 45(e)(8), 613(c)(5), and 6110(k)(3); IRS Notice 2010-54

Full text (IRS public release)

Internal Revenue Service
Department of the Treasury
Washington, DC 20224

Number: 201128005
Third Party Communication: None
Release Date: 7/15/2011
Date of Communication: Not Applicable
Person To Contact:
Index Number: 45.00-00
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Telephone Number:
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Refer Reply To:
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CC:PSI:B6
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PLR-106101-11
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Date:
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March 28, 2011

LEGEND:
Taxpayer -----------------------------------------
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Investor ------------------------
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Corp A
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Corp B
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Corp C
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Corp D
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Corp E
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Corp F
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Corp G
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Corp H
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Corp I
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Corp J
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Location A --------------------------
Location B --------------------------
State A -------------
State B ------------
State C ------------
State D -------------
State E --------------------
Plant
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Additive 1 ---------------------
Additive 2 ------------------------------------ Test Rep 1 ----------------------------------- Test Rep 2 ------------------------------ Test Rep 3 ------------------------------- 2 PLR-106101-11

Coal Seam 1 ------------------------------------
Coal Seam 2 ---------------------------------------------------- A Mines ------------------------------------------- B Mines ---------------------------------------------------------------------------------
$.X --------
$.Y --------
Date 1 --------------------------
Date 2 ----------------------
Date 3 ------------------------
Date 4 --------------------------
Date 5 -------
Date 6 -------------------
Date 7 --------------
Date 8 -------------------
Date 9 -----------------------

Dear --------------:

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:

Taxpayer, a State A limited liability company, is a calendar year taxpayer and employs the accrual method of accounting for both book and tax purposes.

Investor is a State A limited liability company that is classified as a partnership for federal tax purposes.

Investor is 99 percent owned by Corp J, a State E trust company and 1 percent owned by Corp F a State E corporation. Corp F is wholly owned by Corp J. Corp J formed Investor to acquire a membership interest in Taxpayer.

The members of Taxpayer are Investor and Corp A, a State A limited liability company. Corp A is a wholly-owned subsidiary of Corp B and has elected to be taxable as a corporation for federal tax purposes, effective Date 2. Corp B is wholly owned by Corp C, which is wholly owned by Corp D. Corp B is engaged in the business of developing and managing various energy-related projects throughout the United States, including backup power generation projects, power-house operations, cogeneration facilities, coke batteries, and similar energy-related projects. Corp D is the holding company for a number of operating companies engaged in energy-related businesses. Corp D is also the parent company of Corp E, the regulated public electric utility for a portion of State B. Other subsidiaries of Corp D sell coal and coal transportation services throughout the United States. Corp D and its affiliates are calendar-year taxpayers and employ the accrual method of accounting for book and tax purposes. 3 PLR-106101-11

On Date 3 Investor purchased 100% of the Class B membership interests in Taxpayer from Corp A in a transaction treated as a taxable sale of a proportionate share of all of Taxpayer’s assets from Corp A to Investor, followed by a contribution of Taxpayer’s assets by both Investor and Corp A to a newly formed partnership.

Taxpayer constructed a facility consisting of three parallel, independent production lines that are designed to produce refined coal. The three production lines presently are located at Plant. Corp E owns Plant. As originally designed and constructed, each of the three production lines is capable of being operated as a separate unit to produce refined coal. Plant is composed of six coal-fired generating units with an electric generating capacity of approximately 1,400 megawatts in the aggregate. Plant consumes approximately 4.5 million tons of coal a year.

Prior to the transaction with Investor described above, Taxpayer sold production line #1 to Corp H and sold production line #3 to Corp I. Taxpayer retained ownership of production line #2 (the Facility), which it operates to produce refined coal that is sold to Corp E. All of the refined coal is used as a fuel at Plant to produce steam for the generation of electricity.

Taxpayer contracted a designer to design, engineer and construct the Facility, certain material handling equipment, and a building to enclose the Facility and equipment. Mechanical Completion of the Facility was achieved on Date 4. Taxpayer assumed care, custody and control of the Facility from the designer on that same day. Mechanical Completion in Date 4 included the completion of all mechanical and electrical equipment necessary to the operation of the Facility for the production of refined coal. Final completion of the Facility was achieved in Date 5.

A report (the Relocation Report) prepared by an outside consultant describes the components and design of the Facility. The Relocation Report concludes that: (1) the major mechanical, electrical and control equipment, certain auxiliary equipment and the structural steel support for each production line is independent of the other production line and can be relocated without affecting the capability of either production line to produce refined coal, (2) many of the items of common equipment are very site specific and generally would not be compatible with a new site, and (3) disassembly of a production line and installation at a new site is a routine project that can be easily accomplished and relocation of one of the production lines would only require the duplication of certain common equipment, civil works, foundations and filed piping and wiring, which are relatively minor in the context of the complete production line.

Description of the Process and Feedstock.

The process at issue for production of refined coal currently employed at the Facility involves the mixing of proprietary chemicals (additives) with feedstock coal prior 4 PLR-106101-11

to combustion (the Process). The patent for the Process is owned by Corp G and is licensed to Taxpayer. Test results have shown that when mixed with coal, the proprietary additives result in reduced NOX, SO2 and mercury emissions during combustion. Different chemicals are targeted at specific pollutants. Based on the characteristics of the feedstock coal burned at Plant, Taxpayer has chosen a combination of additives that target the reduction of NOX and mercury. In the case of NOX, Taxpayer understands that Additive 1 is believed to cause a portion of the NOX to adhere to, or react with, the additive so that it can be captured and is not emitted. In the case of mercury, Taxpayer understands that Additive 2 is believed to react with the elemental mercury in the feedstock coal so that it is converted into a chemical species of mercury (mercury oxide) that can be effectively captured by particulate control devices.

Emissions Reduction Testing.

For purposes of determining emissions reductions under § 45, Partnership will arrange for pilot-scale combustion testing (and laboratory analysis for redetermination purposes), and will not rely on any continuous emissions monitoring system or other field testing. Corp C engaged the research center of a prominent university (the Center) to conduct tests on behalf of Taxpayer at its pilot-scale combustion furnace (CTF) to determine the emission reductions associated with burning the refined coal compared to the feedstock coal. Corp C has been working with Center for several years in order to investigate and understand the ability of the additives to reduce emissions. Center reports described below state:

The CTF has been extensively used to research and investigate SOX and NOX emissions and the transformation of toxic trace metals (Hg [mercury], As, and Pb) during the combustion of coal and other fuels or waste materials. The CTF is capable of producing gas and particulate samples that are representative of those produced in industrial and full-scale pulverized coal-fired boilers.

For purposes of qualifying the refined coal produced at the Facility, Center conducted pilot-scale combustion tests at its CTF in Date 6 on the blend of feedstock coals of the type typically burned at Plant. Because the Facility was not yet operational at the time of that test, Center reports that it mixed the coal and additives in a manner consistent with the mixing that would occur at the Facility.

The Center reports explain that combustion gas analysis is provided by continuous emission monitors (CEMs) at two locations: the furnace exit, which is used to monitor and maintain a specified excess air level for all test periods, and the outlet of the particulate control device, which is used to assess any air inleakage that may have occurred so that emissions of interest sampled at the back end of the system can be corrected for the dilution caused by the inleakage. Flue gas analyses were obtained 5 PLR-106101-11

from the duct at the outlet of the electrostatic precipitator (“ESP”). Flue gas mercury measurements were obtained separately by a continuous mercury monitor located at the flue gas ducting at the exit of the particulate control device. Center conducted a series of tests on the feedstock and refined coal blends measuring the emissions with these devices.

Test Rep 1 states that the test results indicate that the blend of coal and additives achieved 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. Test Rep 1 states that it is expected the emissions reduction reported would be achieved at full scale using the additive levels tested.

In addition, Corp C engaged Center to conduct tests in Date 7 on feedstock and refined coal samples collected from the Facility during normal operations. Test Rep 2 states that the test results indicate the refined coal samples achieved 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. Test Rep 2 states that it is expected the emission reduction reported would be achieved at full scale using the additive levels in the refined coal.

More recently, Corp C engaged Center to conduct tests in Date 8 on feedstock and Product samples collected from the Facility during normal operations. Test Rep 2 states that the test results indicate the refined coal samples achieved 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. Test Rep 3 states that it is expected the emission reduction reported would be achieved at full scale using the additive levels in the refined coal.

Tested Coal.

Plant currently burns subbituminous coals from a number of mines in Location A located in State C and State D and Location B coals. While Plant uses both Location A and Location B coals to generate electricity, Taxpayer currently produces the refined coal using only Location A coals.

The coal rank of all of the Location A coal burned at Plant is classified by the American Society of Testing Materials as “subbituminous C coal with a gross calorific value of 8,300 to 9,500 btu/lb.” The source of all of the State C Location A coal burned at Plant is Coal Seam 1. The specific mines on Coal Seam 1 at which the coal is currently mined are the A Mines. The source of all of the State B Location A coal burned at Plant is Coal Seam 2 and splits of those seams. The specific mines on Coal Seam 2 and splits of those seams at which the coal is currently mined are the B Mines. The Location A coal blend used by Taxpayer as feedstock for the Process contains 80 to 6 PLR-106101-11

100% State C Location A coal and 20 to 0% State D Location A coal. Variations in the coal blend result from the supply and availability of the State C Location A and State D Location A coals.

Corp C requested that Center test blends of Location A coal that represent the range of Location A coal blends to be used at Plant. As described above, the Location A coal blend burned at Plant contains 80 to 100% State C Location A coal and 20 to 0% State D Location A coal. Accordingly, Center tested a 80% State C Location A coal/20% State D Location A coal blend, a 100% State C Location A coal, and two blends within that range. For purposes of this ruling request, the term “Tested Coal” refers to coal or a blend of coals from 80 to 100% State C Location A coal and 20 to 0% State D Location A coal.

Center reports that based on numerous test results over the past year, refined coal produced from all possible fuel blends are expected to meet the emissions reduction requirements outlined in § 45. Center reported that the emission reduction requirements were met for fuels representing 100% State C coal, 80% State C/20% State D coal blend, and 2 blends within that range. The endpoint fuels were prepared at Center for testing, while the blends were produced at Plant. In each case, Center states that the refined coal met the required emission reduction requirements when compared with the feedstock coal.

Center further reports that it analyzed the variability of fuel N2 and fuel Hg contents between coals from State C and coals from State D since NOx and Hg emissions are of primary concern. In each case, Center states that it is expected that higher fuel N2 and Hg contents will lead to higher emissions of both NOx and Hg, respectively. Center concluded that the N2 and Hg levels from the many samples tested appear typical for many Location A coals and would not be expected to change dramatically from one shipment to another. After reviewing the average levels of N2 and Hg against the combustion test results, Center concluded that any fuel blend tested would represent the range of fuels commonly fired by Plant and could be expected to achieve the required reductions.

Taxpayer expects to continue to operate with the blends and additive levels discussed in the Center reports, which would be consistent with long-term patterns for coal consumed by Plant. If so, samples will be taken for redetermination testing within six months after the last emissions test satisfying the qualified emission reduction requirement. Thereafter, within six months after such date, another set of samples will be taken for redetermination testing. In each case, samples of feedstock and samples of refined coal will be obtained from the Facility using automatic samplers.

Although taxpayer does not currently anticipate making changes to its coal feedstock or additive levels, or using Location B as feedstock for the refined coal, additional testing will be conducted prior to (i) adding coal from any other coal seam or 7 PLR-106101-11

rank to the Facility’s coal feedstock mix (i.e., using Location B), (ii) changing the minimum or maximum percentages of the coal feedstock blend (i.e., using less than 80% State C, or more than 20% State D), or (iii) changing the minimum levels of additives. Such testing will include testing of samples at the endpoints of the new coal feedstock blend and at intermediate blends between the endpoints, as the qualified expert advises is necessary to conclude that a qualified emissions reduction would be expected for any combination within the limits of the blend. In the case of a change in additive levels, tests will also be run at the new minimum levels of additive as the qualified expert advises is necessary to conclude that a qualified emissions reduction will be expected for the new levels of additive.

The Process License Agreement.

Under the Process License Agreement, Corp G granted a license to Taxpayer to use the Process. Taxpayer will make royalty payments to Corp G equal to (i) $0.Y per ton of coal feedstock subjected to the Process through Date 9, and (ii) $0.X per ton thereafter. The initial term of the Process License Agreement is through Date 1. The initial term automatically extends for an additional ten year period unless earlier terminated for cause as set forth in the agreement.

RULINGS REQUESTED

Base on the foregoing, Taxpayer and Investor have requested that we rule as follows:

1. The refined coal produced by using the Process constitutes “refined coal” within the meaning of § 45(c)(7) of the Code, provided that such refined coal is produced by the Taxpayer from feedstock coal that is the same source or rank as the “Tested Coal” and provided further that the refined coal satisfies the qualified emission reduction test stated in § 45(c)(7)(B) of the Code..

2. Testing by Center for qualified emissions reduction as set forth in its test reports satisfies the requirements of Notice 2010-54. Taxpayer may rely on the pilot scale testing conducted at Center (and subsequent permitted laboratory testing as required for a redetermination described in section 6.04(2)(a) or (b) of Notice 2010-54) to satisfy the qualified emission reduction test of § 45(c)(7)(B) of the Code regardless of subsequent normal fluctuations in operating conditions and emissions at Plant.

3. Provided that the feedstock coals during any determination period are from the same coal seams and of the same rank as Tested Coal, all feedstock coal that satisfies that criteria shall be treated as feedstock coal of the same 8
PLR-106101-11
source and rank for purposes of Section 6.04 of Notice 2010-54, regardless of the mine from which such feedstock coal is purchased..

4. Pursuant to section 6.04(2)(b) of Notice 2010-54, Taxpayer may satisfy the redetermination requirement of section 6.04 of Notice 2010-54 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 from the sulfur and mercury content of the feedstock coal and the refined coal used in the most recent determination that meets the requirements of section 6.03 of Notice 2010-54..

LAW AND RATIONALE

Section 45(a) of the Code generally provides a credit against federal income tax for the use of renewable or alternative resources to produce electricity or fuel for the generation of steam. Section 45(e)(8) of the Code provides that, in the case of a producer of “refined coal”, the credit available under § 45(a) of the Code for any taxable year shall be increased by an amount equal to $4.375 per ton of qualified “refined coal” (i) produced by the taxpayer at a “refined coal production facility” during the 10-year period beginning on the date that the facility was originally placed in service, and which is (ii) sold by the taxpayer to an unrelated person during such 10-year period and such taxable year.

For purposes of § 45 of the Code, section 3.01 of Notice 2010-54 provides that the term "refined coal" means a fuel which -- (i) is 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) is sold by the taxpayer with the reasonable expectation that it will be used for purpose of producing steam, and (iii) is 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 (1) 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 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; in the case of production at a facility placed in service before January 1, 2009, a reduction of at least 20 percent of the emissions of NOx and at least 20 percent of the emissions of either SO2 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. 9 PLR-106101-11

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 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 § 613(c)(2), (3), (4)(A), (4)(C), or (4)(I)) 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 and 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 § 613(c)(4) or any necessary or incidental to a process provided for in § 613(c)(4). Any cleaning process, such as a process that uses ash separation, dewatering, scrubbing though 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 removed 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(1)(a) 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. (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 emissions reduction. If a method other than CEMS field testing is used, the Service may require the taxpayer to provide additional proof that the emission reduction has been achieved. The permissible methods include (a) testing using a demonstration pilot-scale combustion furnace if it established that the method accurately measures the emission reduction that would be achieved in a boiler 10 PLR-106101-11

described in section 6.03(a)(a)(i) 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; (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).

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 feedstock coal that occurs after the date of such determination 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 (S) 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 S 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; (b) the S or mercury content of both the feedstock coal and the refined coal do not vary by more than 10 percent from the S and mercury content of the feedstock coal and refined coal used in the most recent determination that meets the requirements of the Notice.

Finally, 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 attached to its tax return on which the credit is claimed a certification that contains the following: (a) a statement that the fuel will result in a qualified emissions reduction when used in the production of steam; (b) 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 feedstock coal used or in the process of producing refined coal from the feedstock coal since the emissions reduction was determined or was most recently determined; and (5) a declaration 11 PLR-106101-11

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.”

With respect to the first issue, the Process starts with several chemical additives added to the feedstock coal prior to its combustion in a furnace. The additives provide the chemical structure that results in the reduction of emissions from NOx, SO2 and mercury during combustion. Section 6.01 of the Notice provides generally that a qualified emission reduction does not include any reduction attributable to mining processes or processes that would be treated as mining, as further defined in the Code, if performed by the mine owner or operator. Section 613(c)(5) describes certain treatment processes that are not considered as mining unless they are provided for in § 613(c)(4) or are necessary or incidental to a process provide for in § 613(c)(4) of the Code. For example, section 6.01(2) of the Notice provides, in part, that any cleaning process such as the application of liquid hydrocarbons or alcohol to the surface of the fuel particle or to the feed slurry, provided such cleaning does not change the physical or chemical structure of the coal, will be considered mining. In the instant case, the Process is not a mining process. Further, section 3.01 of the Notice clarifies § 45(c)(7) of the Code and specifically provides that refined coal includes feedstock coal mixed with an additive or additives. Thus, additive processes which mix certain chemicals or other additives with the coal in order to achieve emission reductions may qualify for the production tax credit for refined coal. Additionally, section 3.03 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 constitutes a “refined coal” within the meaning of § 45(c)(7) of the Code, provided that the refined coal (i) is produced by the Taxpayer from feedstock coal that is the same source or rank as the “Tested Coal” and (ii) satisfies the qualified emission reduction test stated in § 45(c)(7)(B) of the Code .

With respect to the second 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 NOx, SO2 or mercury, provided the method used for any pollutant is a permissible method. Section 6.04(1) 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. Section 6.04(2) provides that in the context of “redetermination” that the redetermination requirement may be satisfied by laboratory analysis establishing either that (i) 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% (40%, in the case of facilities placed in service after December 31, 2008) in comparison to the sulfur or mercury content of the amount of useful thermal energy, excluding any dilution used by materials combined or added 12 PLR-106101-11

during the production process; or (ii) the sulfur or mercury content of both the feedstock coal and the refined coal do not vary by more than 10% from the sulfur or mercury content of the feedstock coal and refined coal used in the most recent determination that meets the requirements of the testing methods for emissions reductions in section 6.03 of the Notice.

In the instant case, Partnership will arrange for pilot-scale combustion testing (and laboratory analysis for redetermination purposes), and will not rely on any continuous emissions monitoring system or other field testing, which is permitted under § 6.03 of the Notice. Specifically, Corp C engaged the Center to conduct testing at its CTF to determine the emission reductions associated with burning the refined coal product compared to the feedstock. For purposes of qualifying the refined coal produced at the Facility, the Center conducted pilot-scale combustion tests at its CTF in Test Rep 1 on the blend of feedstock coals burned at the Plant. Because the Facility was not yet in service, the Center mixed the coal and additives in a manner consistent with the mixing that would occur at the Facility. In Test Rep 2, the Center conducted tests on feedstock and refined coal product samples collected from and produced by the Facilities.

In Test Rep 1, the Center reported that the test results indicated that the blend of coal and additives achieved the required emissions reductions. The test results in Test Rep 2 indicated that the refined coal samples achieved the required emissions reductions. Based on the foregoing we conclude that testing by the Center for qualified emission reductions as set forth in its test reports satisfies the requirements of Notice 2010-54. Taxpayer may establish a qualified emission reduction through testing by the Center at its combustion research facility or similar pilot-scale combustion testing facilities under Notice 2010-54, regardless of subsequent normal fluctuations in operating conditions at the Plant.

With respect to the third 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 market place 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 provides that a determination or redetermination of a qualified emissions reduction is valid until the occurrence of the earliest of the following events: (1) six months have passed since the date of such determination or redetermination; (2) a change in the source or rank of feedstock coal that occurs after the date of such determination or redetermination; or (3) a change in the process of producing refined 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 seams and of the same rank as Tested Coal, all feedstock coal that satisfies that criteria shall be treated as feedstock 13 PLR-106101-11

coal of the same source or rank for purposes of section 6.04 of Notice 2010-54, regardless of the mine from which such feedstock coal is purchased

With respect to the fourth 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 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 – (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 S and mercury content of the feedstock coal and refined coal used in the most recent determination that meets the requirements of the Notice. Accordingly, we conclude that Taxpayer may satisfy the redetermination requirement of section 6.04 of Notice 2010-54 by laboratory analysis establishing that the s and mercury content of both the feedstock coal and the refined coal, on average do not vary by more than 10 percent from the sulfur and mercury content of the feedstock coal and the refined coal used in the most recent determination that meets the requirements of section 6.03 of Notice 2010-54.

No opinion is expressed regarding any other issue not specifically addressed in this ruling letter. In particular, no opinion is expressed with respect to whether (1) Taxpayer, Investor or any of their affiliates is the Producer of the refined coal for purposes of § 45(e)(8) of the Code; or (2) the Facility was, in fact, placed in service prior to January 1, 2010.

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.

This ruling is directed only to the Taxpayer who requested it. Section 6110(k)(3) of the Code provides it may not be used or cited as precedent. We are sending a copy of this letter ruling to the Industry Director.

Sincerely,

Peter C. Friedman
Senior Technician Reviewer, Branch 6
Office of Associate Chief Counsel (Passthroughs & Special Industries)