IRS approves refined-coal testing and facility-relocation rules

Plain-English summary

A partnership operated a relocated facility that mixed chemical additives with low-sulfur coal to reduce nitrogen oxide and mercury emissions. The IRS ruled that the resulting product could qualify as refined coal under § 45 when the feedstock came from the tested source region or rank and met the emissions-reduction test. Coal from different mines could be treated as the same source when it shared that region and rank. Verified pilot-furnace testing was acceptable, and increasing additive rates or later returning to the certified rate would not count as a process change. Laboratory redeterminations could use the Notice's 10 percent content ranges, and a delayed written test report could support production from the test date if received within 90 days. Relocation or component replacement would not reset the facility's placed-in-service date if original used property remained more than 20 percent of total value, but the IRS did not decide the original placed-in-service date or whether any investor bore enough production risk to claim the credit.

Ruling snapshot

• Question: Would the refined-coal process, pilot testing, redetermination methods, delayed reports, additive changes, and facility relocation satisfy § 45 and Notice 2010-54?
• Outcome: Approved, subject to the stated testing, timing, feedstock, emissions, and original-property conditions
• Key authorities: IRC § 45(c), (d), and (e); Notice 2010-54

Full text (IRS public release)

Internal Revenue Service Department of the Treasury
Washington, DC 20224

Number: 201448010 [Third Party Communication:
Release Date: 11/28/2014 Date of Communication: Month DD, YYYY]
Index Number: 45.00-00
Person To Contact:
-------------------------- ----------------------, ID No. ------------
-------------------------------- Telephone Number:
---------------------------------------- ---------------------
----------------------------------------------- Refer Reply To:
CC:PSI:B06
PLR-111553-14
Date:
August 13, 2014

LEGEND

Taxpayer = --------------------------------
-----------------------
Investor 1 = -----------------------------------
Investor 2 = ----------------------
Partnership = ---------------
Investor 4 = --------------------------
Investor 5 = ------------------------
Investor 6 = ------------------------
Company A = ------------------
Company B = ----------------
Company C = -----------------------------------
Company D = -----------------------------------------------
State A = ------------
State B = -------------
State C = ----------------
State D = ------------
State E = ------------
State F = ----------------
Original Site = ----------------------
Original Generating Station = --------------------------------------
Site = -----------------------------
Generator = ------------------------------------------------
Generating Station = ---------------------------------------
Year a = ------
Date a = -----------------
Date b = ---------------------
Date c = ---------------------
Chemical A1 = ------
Chemical A2 = -----------------------------
PLR-111553-14 2

Chemical B = ------------------------
Center = ------------------------------------------------------------------------------------------
----------------------------------------------------------

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.

Background

   Partnership is a State A limited liability company classified as a partnership for

federal income tax purposes. Partnership is a calendar year taxpayer and uses the
accrual method of accounting for book and tax purposes. Partnership is engaged in
purchasing raw coal, converting it to refined coal, and selling the refined coal.

   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.

   Taxpayer is a State A corporation. Taxpayer is a calendar year taxpayer and

uses the accrual method of accounting for book and tax purposes.

    Each of Investor 4, Investor 5 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.
PLR-111553-14 3

   The members of Partnership are Investor 1, Investor 2, Taxpayer, Investor 4,

Investor 5, 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 Partnership. 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.
PLR-111553-14 4

   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
PLR-111553-14 5

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).
PLR-111553-14 6

   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).

RULINGS REQUESTED

Based on the foregoing, you have requested that we rule as follows:

   1.     The refined coal produced and sold using the Process and Technology

constitutes “refined coal” within the meaning of section 45(c)(7) of the Internal Revenue
Code of 1986, as amended (the Code), provided that such refined coal is produced from
feedstock coal that is from the same source region or rank as the Tested Coal
described herein and provided further that the refined coal satisfies the qualified
emission reduction test in section 45(c)(7)(B) of the Code.

    2.     Provided that the feedstock coals used to produce refined coal during any

determination period is from the same source region and of the same rank as the coal
subject to the most recent determination or redetermination, 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 and will not require a redetermination to establish qualified
emission reductions.

    3.    Testing by the Center for qualified emissions reductions as described in

the Report satisfies the requirements of the Notice. Partnership may treat the required
emission reductions in section 45(c)(7)(B) of the Code as having been met based on the
results from the Pilot Furnace testing at the Center or other similar pilot-scale
combustion testing facilities (and subsequent permitted laboratory testing as required
for a redetermination described in section 6.04(2)(a) or (b) of the Notice) regardless of
subsequent normal fluctuations in operating conditions and emissions at the Generating
Station.

   4.     Increasing the amounts of chemical additives to the feedstock coal to a

higher level per ton of feedstock coal than the rate shown to have produced a qualified
emissions reduction in a determination or redetermination will not be construed as a
“change in the process of producing refined coal from the feedstock coal” requiring a
redetermination under section 6.03 of the Notice, nor will later resuming application at
the rate used in such original determination or redetermination constitute such a
change.

   5.     The results of a test set forth in a redetermination test report 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, or if the test was done before
PLR-111553-14 7

Partnership acquired the Facility.

   6.     Pursuant to section 6.04(2)(b) of the Notice, 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 refined
coal, on average, do not vary by more than 10 percent below the bottom of (nor more
than 10 percent above the top of) the range of sulfur and mercury content of both the
feedstock coal and refined coal used in the most recent determination pursuant to
section 6.03 of the Notice.

  7.       If the Facility was “placed in service” prior to January 1, 2012 within the

meaning of section 45(d)(8)(B) of the Code, a subsequent modification or relocation of
the Facility, 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, provided the fair
market value of the original property of the modified or relocated Facility is more than 20
percent of the Facility’s total fair market value at that time.

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 section 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 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.
PLR-111553-14 8

  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).
PLR-111553-14 9

   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
PLR-111553-14 10

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
PLR-111553-14 11

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
PLR-111553-14 12

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
PLR-111553-14 13

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.

    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.

                                Sincerely,




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