PLR 201123016: IRS approves refined-coal credit treatment and related testing methods

Plain-English summary

A partnership planning to produce refined coal asked the IRS about the requirements for claiming the refined-coal credit under § 45. The IRS ruled that the taxpayer's chemical-additive process could produce refined coal if the feedstock met the specified source or rank conditions and the product satisfied the qualified-emission-reduction test. It also approved the use of the described pilot-scale testing, the treatment of coal from specified seams and ranks as having the same source or rank, and certain relocations or component replacements without creating a new placed-in-service date. The rulings were subject to the conditions stated in the letter, and the IRS did not decide whether the taxpayer was the producer or whether the facilities were actually placed in service before January 1, 2010.

Ruling snapshot

• Question: Does the taxpayer's refined-coal process and testing support the § 45 credit, and can facility changes preserve the original placed-in-service date?
• Outcome: Approved, subject to the letter's conditions and limitations.
• Key authorities: IRC §§ 45, 613, 6110; Notice 2010-54; Treas. Reg. § 1.46-3.

Full text (IRS public release)

Internal Revenue Service
Department of the Treasury
Washington, DC 20224

Number: 201123016
Third Party Communication: None
Release Date: 6/10/2011
Date of Communication: Not Applicable
Index Number: 45.00-00
Person To Contact:
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----------------------, ID No. -------------
---------------------------------------------------------- Telephone Number:
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-------------------------------------------- Refer Reply To:
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CC:PSI:B6
PLR-144856-10
Date: March 1, 2011

LEGEND:
Taxpayer ------------------------------------------------------
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Company ------------------------------------------- Corp A --------------------------------- Corp B ---------------------------------- Corp C --------------------------------------- Corp D ---------------------------------------------------- Corp E -------------------------------- Corp F ----------------------------------------- Corp G ---------------------- Location A -------------------------- State A ------------- State B ------------ State C ------------ State D ------------ Plant ------------------------------------------- Additive 1 --------------------- Additive 2 ------------------------------------ Test Rep 1 ----------------------------------- Test Rep 2 ------------------------------ Coal Seam 1 ------------------------------------ Coal Seam 2 --------------------------------------------------- A Mines ------------------------------------------ B Mines ---------------------------------------------------------------------------------
$X --------
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PLR-144856-10

$Y
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$Z
--------
Date 1 --------
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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 has represented the facts to be as follows: Taxpayer is a State A limited liability company that is classified as a partnership for federal income tax purposes. Taxpayer is a calendar year taxpayer and employs the accrual method of accounting for both book and tax purposes

The members of Taxpayer are Corp A, a State A limited liability company and Corp B, a State A corporation. Corp A is a wholly-owned subsidiary of Corp B. Pursuant to § 301.7701-3(c) of the Federal Income Tax regulations, Corp B has elected to treat Corp A as a corporation for federal income tax purposes. Corp B is wholly- owned by Corp C, which is wholly-owned by Corp D. Corp A and Corp B file a consolidated federal income tax return with Corp D, which is the parent of the affiliated group. Corp D and its affiliates are calendar-year taxpayers and employ the accrual method of accounting for book and tax purposes.

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.

Taxpayer will purchase 100% of the membership interests in Company from Corp B effective January 1, 20---. Taxpayer intends for the acquisition of 100% of the membership interests in Company to be treated as an acquisition of the assets of Company, including Facility and Facility No. 2 (the Facilities), for federal income tax purposes. Consequently, references to Taxpayer and Company are used interchangeably.

Company constructed Facility and Facility No. 2 as two independent and separate units designed to produce refined coal. Facility and Facility No. 2 are located at Plant. Corp E and Corp F each own an undivided interest in Plant. Neither Corp E nor its affiliates own an interest in Corp F and Corp F does not own an interest in Corp E or its affiliates. Plant is composed of two coal-fired generating units with an electric 3 PLR-144856-10

generating capacity of approximately 600 megawatts each. Plant consumes approximately five million tons of coal a year. Facility and Facility No. 2 are operated to produce refined coal that is sold to Corp E. A portion of the refined coal is resold by Corp E to Corp F based upon Corp F’s undivided interest in Plant. All of the refined coal is used as a fuel at Plant to produce steam for the generation of electricity.

Facility and Facility No. 2 are each capable of being operated as a separate unit (or separate refined coal production facilities) to produce refined coal. A report (Relocation Report) prepared by an outside consultant describes the components and design of the two Facilities. The Relocation Report concludes that: (1) the major equipment, certain auxiliary equipment and the structural steel support for each unit is independent of the other unit and can be relocated without affecting the capability of either unit 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 unit and installation at a new site is a routine project that can be easily accomplished and relocation of one unit would only require the duplication of certain common equipment and civil works and foundations, which are relatively minor in the context of the complete production line.

Facility No. 2 will be physically isolated from Facility and will no longer be operated to provide refined coal to Plant In the future, Facility No. 2 may be relocated to another location. In that case, all of the essential components of Facility No. 2 will be relocated and retained.

Description of the Process and Feedstock

The process at issue for production of refined coal involves the mixing of proprietary chemicals (additives) with feedstock coal prior to combustion (the Process). The patent for the Process is owned by Corp G and is sublicensed to Company. Test results described herein 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.
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PLR-144856-10

Corp C engaged the research center of a prominent university (the Center) to conduct tests on behalf of Company 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 the Center for several years in order to investigate and understand the ability of the additives to reduce emissions. The 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 Facilities, the Center conducted pilot-scale combustion tests at its CTF in Test Rep 1 on the blend of feedstock coals burned at Plant. Because the Facilities were not yet in service, Center reports that it mixed the coal and additives in a manner consistent with the mixing that would occur at the Facilities.

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 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. The Center conducted a series of tests on the feedstock and refined coal blends measuring the emissions with these devices.

Test Report 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 The test report 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 the Center to conduct tests in Test Rep 2 on feedstock and refined coal samples collected from the Facilities during normal operations. Test Report 2 states that the test results indicate the refined coal samples achieved the required reductions in both NOX and total mercury emissions (both 5 PLR-144856-10

determined on a lb/Btu basis) to satisfy the requirements of at least 20% NOX reduction and at least 40% mercury reduction. Test Report 2 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. The coal rank of all of 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 --------to --------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 D Location A coal burned at Plant is Coal Seam 2 and splits of those seams. The specific mines on Coal Seam 2 at which the coal is currently mined are the B mines. The coal blend burned at Plant contains 80 to 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 the Center test blends of coal that represent the range of blends to be used at Plant. As described above, the coal blend burned at Plant contains 80 to 100% State C Location A coal and 20 to 0% State D Location A coal. Accordingly, the 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.

The 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. The 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 the Center for testing, while the blends were produced at Plant. In each case, the Center states that the refined coal met the required emission reduction requirements when compared with the feedstock coal.

Further, the Center reports that it analyzed the variability of fuel N2 and fuel mercury contents between coals from State C and coals from State D since NOx and mercury emissions are of primary concern. In each case the Center states that it is expected that higher fuel N2 and mercury contents will lead to higher emissions of both NOx and mercury, respectively. The Center concluded that the N2 and mercury 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 mercury against the combustion test results, the Center 6 PLR-144856-10

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.

Company 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 Facilities using automatic samplers. This sampling and testing procedure is intended to satisfy the six-month redetermination requirement set forth in section 6.04 of Notice 2010-54, IRB 2010-40, October 4, 2010 (the Notice).

Although Company does not currently anticipate making changes to its coal feedstock or additive levels, additional testing will be conducted prior to (i) adding coal from any other coal seam or rank to the Facilities’ coal feedstock mix, (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 (License Agreement), Corp G granted a license to Corp C to use the Process. Corp C provided certain services to Corp G in lieu of paying an initial license fee to Corp G upon execution of the License Agreement. For the use of the Process at certain designated sites, Corp C has or will make royalty payments to Corp G equal to (i) $.Y per ton of coal feedstock subjected to the Process during the first three years of the term of the License Agreement, and (ii) $.X per ton thereafter. The initial term of the License Agreement at the designated sites is ten years. The initial term automatically extends for an additional ten year period unless earlier terminated for cause as set forth in the License Agreement.

Corp C subsequently entered into the Sublicense with the Company to use the Process at the Facilities. Under the Sublicense, the Company assumes all obligations and liabilities of Corp C under the License Agreement with respect to the use of the Process at the Facilities. The Company will make royalty payments to Corp C equal to (i) $.Y per ton of coal feedstock prior to ----------------------, and $.X per ton of feedstock 7 PLR-144856-10

thereafter until the effective date of federal or state regulations requiring the Plant to reduce or otherwise control mercury emissions, and (ii) $Z per ton of coal feedstock on and after the effective date of federal or state regulations requiring the Plant to reduce or otherwise control mercury emissions (currently anticipated to be -------). This increase in royalty payments reflects the value of the technology as an alternative to the construction and operation of pollution control equipment for mercury emission control. The Sublicense will terminate on Date 1, unless the License Agreement is earlier terminated. Unless the Sublicense is extended, the Company will not be able to produce refined coal beyond Date 1.

Rulings Requested

Based on the foregoing, Taxpayer has 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 Internal Revenue Code, provided that such
   refined coal is produced by 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.

2. 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
   and emissions at the 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 source or
   rank for purposes of section 6.04 of Notice 2010-54, regardless of the mine from
   which such feedstock coal is purchased.

4. Provided Facility or Facility No. 2 was “placed in service” prior to January 1,
   2010, within the meaning of § 45(d)(8), relocation of Facility or Facility No. 2 to a
   different location after December 31, 2009, or replacement of part of a Facility or
   Facility No. 2 after that date, will not result in a new placed in service date for
   Facility for purposes of § 45 provided the fair market value of the used property is
   more than 20 percent of the total fair market value of relocated Facility or Facility
   No. 2 at the time of relocation or replacement.
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   PLR-144856-10

   LAW AND RATIONALE

Process and testing of refined coal

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.

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, 2010.

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 9 PLR-144856-10

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 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 10 PLR-144856-10

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 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.”

Addition or improvement to an existing facility

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 steel industry fuel, the facility (or any modification to the 11 PLR-144856-10

facility) must be placed in service before January 1, 2010. 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, 2010. Section 3.07 of the Notice provides that the year in which property is placed in service is determined under the principles of § 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 as 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 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, § 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 12 PLR-144856-10

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 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, Corp C engaged the Center to conduct test 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 Facilities, 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 Facilities were not yet in service, the Center mixed the coal and additives in a manner consistent with the mixing that would occur at the Facilities. In Test Rep 2, the Center conducted tests on feedstock and refined coal product samples collected from and produced by the Facilities.

In Test Report 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 13 PLR-144856-10

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 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, we understand that, Facility or Facility No. 2 may be relocated to another location in the future. In that case, all of the essential components of Facility or Facility No. 2 will be relocated and retained. Similarly, during the life of Facility or Facility No. 2 it may be necessary to replace certain major components. In the event of relocation (of Facility or Facility No. 2) or replacement of a component, there should be no change in the placed in service date of Facility or Facility No. 2 as long as the test described in § 5.02 of the Notice has been met. Based on the foregoing, we conclude that provided Facility or Facility No. 2 was “placed in service” prior to January 1, 2010, within the meaning of § 45(d)(8), relocation of Facility or Facility No. 2 to a different location after December 31, 2009, or replacement of part of Facility or Facility No. 2 after that date, will not result in a new placed in service date for Facility or Facility No. 2 for purposes of § 45 provided the fair market value of the used property is more that 20 percent of relocated Facility’s or Facility No.2’s total fair market value at the time of relocation or replacement.

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 is the Producer of the refined coal for purposes of § 45(e)(8) of the Code; or (2) the Facilities were, 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. 14 PLR-144856-10

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)