Refined-coal process and testing qualify for section 45 credit rules

Plain-English summary

A partnership operated a relocated facility that mixed proprietary additives with coal to reduce nitrogen oxide and mercury emissions before the coal was burned to generate electricity. The IRS ruled that coal produced through the process could be refined coal under section 45 when it used feedstock matching the tested source or rank and met the required emissions reductions. It approved the proposed treatment of coal from specified regions, pilot-scale testing, laboratory redeterminations, and reliance on test reports received within 90 days after timely testing. Prior ownership transfers did not change the facility's placed-in-service date, and relocation would not reset that date if used property represented more than 20 percent of the relocated facility's total value. The IRS did not decide when the facility was actually placed in service, whether refined coal was sold to unrelated persons, or whether the taxpayer bore enough production risk to claim the credit.

Ruling snapshot

• Question: Did the additive process, emissions testing, redetermination methods, transfers, and relocation satisfy specified section 45 refined-coal credit rules?
• Outcome: Approved
• Key authorities: IRC § 45(c)(7), (d)(8), (e)(8); Notice 2010-54

Full text (IRS public release)

Internal Revenue Service Department of the Treasury
Washington, DC 20224

Number: 201538005 [Third Party Communication:
Release Date: 9/18/2015 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-109850-15
Date:
June 8, 2015

LEGEND:

Taxpayer = ----------------------------
----------------------
Company A = ----------------------------------
Company B = ------------------------------------
Company C = ---------------------
Company D = -----------------------------
Company E = ---------------
Company F = --------------------------
Company G = ----------------------------
Company H = ------------------------------
Company I = -------------------
Business A = --------------------------------------------------
Utility A = ---------------------------------
Utility B = ------------------------------
Licensor = ----------------------
State A = ------------
State B = ---------
State C = -------------
State D = ---------
State E = ------------
State F = ------------
Plant A = ---------------------------------------
Plant B = --------------------------
Date 1 = ------
Date 2 = -------------------
Date 3 = ------------
Date 4 = --------------------
Date 5 = ----------------------

PLR-109850-15 2

Date 6 = ------------------------
Date 7 = ------------------------
Date 8 = ---------------------------
Additive 1 = --------------------
Additive 2 = ----------------------
Center = ------------------------------------------------------------------------------------------
---------
Test Rep = ------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------
--------------
a% = ------
b% = ------
c% = ------
d% = ------
source region A = ------------------
source region B = --------------------------

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

   This is in response to your request for rulings, dated March 12, 2015 and

amended dated May 20, 2015, submitted by your authorized representative, concerning
the federal income tax consequences of the transaction described below.

Background

   Company C, a State A limited liability company, is a fiscal year taxpayer and

employs the accrual method of accounting for both book and tax purposes. The
members of Company C are Company A, a State A limited liability company, and
Company B, a State B limited liability company. Company B is wholly owned by
Taxpayer, a State C limited liability company which in turn is wholly owned by Company
D, a publicly traded State A corporation that is the holding company for a diverse group
of subsidiaries engaged in Business A. Company A is wholly owned by Company E, a
State A limited liability company that is classified as a partnership for United States
federal tax purposes.

    Company C owns a facility for the production of refined coal that was first placed

in service by Company E at a site adjacent to Plant A in State D on or about Date 1 and
produced and sold refined coal with the expectation that it would be burned to produce
steam. Because Utility A, the owner of Plant A, decided to shut down Plant A,
Company E did not continue producing refined coal in the facility at that location after
Date 2, and contracted with Company F to dismantle the facility and temporarily place it
into storage.

PLR-109850-15 3

   Subsequently, in Date 3, Company E contributed the facility to Company A,

which in turn contributed the facility to Company C. Immediately following that
contribution, Company A owned all of the interests in Company C, such that Company
C was disregarded as a separate entity from Company A for U.S. federal tax purposes.

     On Date 4, Company C entered into contracts with Utility B to locate the facility

on a site adjacent to Plant B in State C, and to sell refined coal produced in the facility
to Utility B. Thereafter, in Date 5, Company C contracted with Company G to relocate
and reassemble the facility at the site adjacent to Plant B. In connection with the
relocation of the facility to State C, all essential components of the facility were
relocated and retained. The facility resumed production of refined coal at the State C
location on Date 6.

   On Date 7, Company B acquired all of the class B membership interests in

Company C from Company A in a transaction treated as a taxable sale or exchange of
a proportionate share of all of Company C’s assets, followed by a contribution of such
assets to a newly formed partnership pursuant to § 721 and Revenue Ruling 99-5,
1999-1 C.B. 434. The limited liability agreement of Company C sets forth the members’
agreement regarding the respective rights and obligations of the members in Company
C, the management and related decision-making of Company C, and certain related
matters. Company I, a State A limited liability company and affiliate of Company E, is
the non-member manager of Company C.

   Pursuant to its agreements with Utility B, Company C purchases coal feedstock

from Utility B. The coal supply agreement does not prohibit Company C from
purchasing coal feedstock from third parties. The feedstock coal purchased by
Company C typically is coal that Utility B itself purchased from third party vendors,
consistent with its coal specifications. Company C uses the Process (as described
below) to produce refined coal that it sells to Utility B pursuant to a refined coal sales
agreement. Company C at any given time produces refined coal from one or more coal
source regions or ranks, presently expected to be bituminous coal obtained from
various mines in coal source region A and subbituminous coal obtained from various
mines in coal source region B. However, it is possible that in the future Company C will
obtain feedstock coal from other coal source regions or ranks which may be sourced
from other mines. The refined coal is sold to Utility B, which then feeds it to the boilers
at Plant B. Currently, Utility B expects to burn a blend of refined coal at Power Plant B
consisting of approximately a% from source region A and approximately b% from
source region B, but it is possible that for some short term operations the blend ratios
could vary from c% source region A and d% source region B, up to b% source region A
and a% source region B. All of the refined coal produced in the facility is expected to be
used as a fuel at Plant B to produce steam for the generation of electricity. However,
any refined coal not purchased by Utility B can be sold to one or more third parties.

  Company C has no employees. Rather, it entered into an operations and

maintenance agreement with Company G, a State A limited liability company and

PLR-109850-15 4

affiliate of Company A. Pursuant to that agreement, Company G will operate, repair
and maintain the facility in accordance with an agreed operating plan, will make
arrangements to coordinate delivery of spare parts and supplies, will coordinate
deliveries of coal feedstock purchases and sales of refined coal, and will perform certain
administrative functions in support thereof.

Description of the Process

     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
to combustion (the Process). The patent for the Process is licensed by Licensor to
Company C. Licensor is entitled to certain per ton royalties based on production for the
use of its technology. 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 B, Company C has chosen a
combination of additives that target the reduction of NOx and mercury. In the case of
NOx, Company C 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, Company C 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, Company C 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. Company C engaged the research center of a prominent university (the
Center) to conduct tests on behalf of Company C at its circulating fluidized-bed
combustor (CFBC) to determine the emission reductions associated with burning the
refined coal compared to the feedstock coal. The Center report described below states:

          The CFBC has been extensively used to investigate SOX, NOX and
          [mercury] emissions and potential bed material agglomeration. The
          CFBC is capable of producing gas and particulate samples that are
          representative of those produced in industrial- and full-scale
          [circulating fluidized-bed (CFB)] boilers.

The CFBC is capable of producing gas and particulate samples that are representative
of those produced in industrial and full-scale CFB boilers. A baghouse is used for
particulate control. For purposes of qualifying the refined coal produced at the facility,
Center conducted pilot-scale combustion tests at its CFBC on Date 8 on feedstock
coals of the type typically burned at Plant B.

PLR-109850-15 5

   Test Rep explains that combustion gas analysis is provided by continuous

emissions monitors at two locations: the baghouse outlet and the convective pass
outlet. In addition, a continuous mercury monitor was installed at the outlet of the
baghouse during each test. Center conducted a series of tests on the feedstocks and
refined coals, measuring the emissions with these devices. At the completion of each
feedstock and refined coal test period, fuel and fly ash samples were collected and
submitted for analysis.

   Test Rep states that, for each of the coals tested, application of the additives at

rates specified in the report 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. Further, Test Rep also
states that when applying the highest required additive rate, any one of, or blend of coal
from, the two coal source regions tested would be expected to achieve the required
emissions reduction when used to produce refined coal at full scale.

Tested Coal

    Plant B currently burns coal obtained from various mines located in State C,

State E, and State F. Company C produces refined coal using this coal and sells that
refined coal to Plant B which burns it to generate electricity from steam. The rank of the
coal from source region A is classified by the American Society of Testing Materials
(ASTM) as high volatile bituminous coal, which is expected to have a gross calorific
value of 10,500 to 14,000 btu/lb, and the rank of the coal from source region B is
classified by ASTM as subbituminous coal, which is expected to have a gross calorific
value of 8,300 to 11,500 btu/lb.

   On Date 8 Company C requested that Center test each of the coals that it

expects to use to produce refined coal that will be sold for consumption in Plant B. The
report issued by Center with respect to these tests states that the emission reduction
requirements outlined in § 45 for NOx and mercury were satisfied when comparing the
results of burning the endpoint fuels to the results of burning the feedstock coals.
Further, Test Rep concludes that any one of, or blend of coal from, the two coal source
regions tested would be expected to satisfy the requirements of at least a 20 percent
nitrogen oxide reduction and at least a 40 percent mercury reduction using the highest
additive levels described in the report.

   Company C currently expects to continue to operate with feedstock coals from

the same source regions and of the same rank as those discussed in Test Rep.
Samples will be taken for redetermination testing within six months after the last
emissions test satisfying the qualified emission reduction requirement to redetermine
the Approved Application Rates (defined below). Thereafter, within six months after
such date, another set of samples will be taken for redetermination testing. In each
case, samples will be collected and prepared in accordance with sampling and testing
procedures set forth in Company C’s operating protocols. Although testing and

PLR-109850-15 6

preliminary reporting is done timely, occasionally the Center is not able to issue the final
report until after the six-month period.

    For purposes of this ruling letter, the term “Tested Coal” refers to the most

recently tested samples tested by Center with respect to which Center has advised the
Taxpayer of the application rates for the liquid and powder additives that achieved at
least a 40 percent reduction in mercury emissions and at least a 20 percent reduction in
nitrogen oxide emissions (the “Approved Application Rates”). Although Company C
does not currently anticipate making changes to its coal feedstock or additive levels, or
using other coal sources or ranks, additional testing will be conducted prior to acquiring
coal feedstock from a different coal source region or of a different rank than reflected in
the Tested Coal used in the then applicable test report. If the Tested Coal is a blend of
coal, the Approved Application Rates will be such that the Center considers any one of,
or blend of coal from, the coal source regions in the Tested Coal would be expected to
satisfy the qualified emissions reduction test requirements. In the case of a change in
the 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.

RULINGS REQUESTED

   Based on the foregoing, you 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
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. Provided that the feedstock coals used to produce refined coal during any

determination or redetermination period are from one of the coal source regions
represented in the Tested Coal or any blend thereof, and of the same rank as such
Tested Coal, all such feedstock coal shall be treated as feedstock coal of the same
source and rank for purposes of section 6.04 of Notice 2010-54, regardless of the mines
from which such feedstock coal is purchased.

   3. Testing by Center for qualified emissions reduction as set forth in its test

reports (including interim reports) satisfies the requirements of Notice 2010-54. The
Taxpayer may rely on the pilot scale testing conducted at Center or a similar pilot-scale
combustion testing facility under Notice 2010-54 (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.

   4. Pursuant to section 6.04(2)(b) of Notice 2010-54, the Taxpayer may satisfy

the redetermination requirement of section 6.04 of Notice 2010-54 by laboratory

PLR-109850-15 7

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 ten percent below the bottom of
(nor more than ten percent above the top of) the range of sulfur content and the range
of 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.

    5. The Taxpayer may rely upon the results set forth by the Center in a

redetermination test report for production after the date of the testing even if the report
is not received until after the six month period specified in section 6.04(1)(i) of Notice
2010-54.

  6. The transfers of the facility by Company E to Company A, and then by

Company A to Company C subsequent to its placed-in-service date will not affect the
placed-in-service date of the facility for purposes of §45.

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

the meaning of §45(d)(8), relocation of the facility to a different location after December
31, 2011, will not result in a new placed-in-service date for the facility for purposes of
§45 provided the fair market value of the used property is more than twenty percent of
the facility’s total value (the cost of the new property plus the value of the used property)
at the time of relocation or replacement.

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 the 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, 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

PLR-109850-15 8

coal (excluding any dilution caused by materials combined or added during the
production process), as compared to the emissions released when burning the
feedstock coal or comparable coal predominantly available in the marketplace as of
January 1, 2003.

  Section 45(d)(8) of the Code generally provides that the term “refined coal

production facility” means a facility which is placed in service after October 22, 2004
and before January 1, 2012.

    Section 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 are 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 through a centrifugal pump,
spiral concentration, gravity concentration, flotation, application of liquid hydrocarbons
or alcohol to the surface of the fuel particles or to the feed slurry provided such cleaning
does not change the physical or chemical structure of the coal, and drying to remove
free water, provided such drying does not change the physical or chemical identity of
the coal, will be considered as mining.

   Section 6.03(1) of the Notice provides, in part, that emissions reduction may be

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

   Section 6.03(2) of the Notice provides that methods other than CEMS field

testing may be used to determine the emission reduction. The permissible methods
include (a) testing using a demonstration pilot-scale combustion furnace if it establishes

PLR-109850-15 9

that the method accurately measures the emission reduction that would be achieved in
a boiler described in section 6.03(1)(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; 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).

     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 (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.

    Section 6.05 of the Notice provides that the certification requirement of section

3.01(1)(c) of the Notice is satisfied with respect to fuel for which the refined coal credit is
claimed only if the taxpayer attaches to its tax return on which the credit is claimed a
certification that contains the following: (1) a statement that the fuel will result in a
qualified emissions reduction when used in the production of steam; (2) a statement
indicating whether CEMS field testing was used to determine the emissions reduction;
(3) if CEMS field testing was not used to determine the emissions reduction, a
description of the method used; (4) a statement that the emissions reduction was
determined or redetermined within the six months preceding the production of the fuel
and that there have been no changes in the source or rank of the feedstock coal used in
the process of producing refined coal from feedstock coal since the emissions reduction
was most recently determined or redetermined; and (5) a declaration signed by the

PLR-109850-15 10

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 Notice 2010-54 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 Notice 2010-54 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. Notice 2010-54 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 results 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 §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 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 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, the emissions profile of the refined coal product

is compared to the emissions profile of either the feedstock coal or a comparable coal
predominantly available in the marketplace as of January 1, 2003. Section 3.03 of the
Notice provides that a “comparable coal” is defined as coal that is of the same rank as
the feedstock coal and that has an emissions profile comparable to the emissions profile
of the feedstock coal. Section 6.04 of 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

PLR-109850-15 11

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 used to produce refined coal during any determination or
redetermination period are from the one of the coal source regions represented in the
Tested Coal or any blend thereof, and of the same rank as the Tested Coal, all such
feedstock coal shall be treated as feedstock coal of the same source and rank for
purposes of section 6.04 of Notice 2010-54, 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) 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, Company C will arrange for pilot-scale combustion
testing, and will not rely on any continuous emissions monitoring system or other field
testing, which is permitted under section 6.03 of the Notice. Specifically, Company C
will arrange with the Center to conduct testing (including redetermination testing) at its
CFBC 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 its
CFBC as documented in the Test Rep. In conducting such tests, the Center conducted
tests on the feedstock from each coal source regions, and then mixed separate samples
of each feedstock with the additives so that it could conduct tests on the refined coal
product. In its report, the Center reported that the test results indicated that the blend of
coal and additives achieved the required emissions reductions. In addition, Test Rep
concluded that that any blend of coal from the two coal source regions included in the
Tested Coal would be expected to achieve the required emissions reduction when used
to produce refined coal at full scale using the highest additive levels tested. 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
Notice 2010-54. Qualified emissions reduction through testing by the Center at its
combustion research facility or similar pilot-scale combustion testing facilities under
Notice 2010-54 may be relied upon.

    With respect to the fourth issue, section 6.04(2) of Notice 2010-54 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

PLR-109850-15 12

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 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 that 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 ten percent below the bottom of (nor
more than ten percent above the top of) the range of sulfur content and the range of
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.

    With respect to the fifth issue, it is intended that Company C will engage in

redetermination testing every six months, or more frequently if required pursuant to
Notice 2010-54. However, the Center is not always able to issue the written report
required by section 6.03(2)(a) of Notice 2010-54 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. 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 may be relied upon for production
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 Notice 2010-54, so long as Company C receives the
written report 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.

   With respect to the sixth issue, the placed-in-service language in §45(d)(8)

focuses on the facility, and does not, by its terms, require the facility to have been
placed in service by the taxpayer claiming the credit. Accordingly, we conclude that the
transfers of the facility by Company E to Company A, and then by Company A to
Company C subsequent to its placed-in-service date will not affect the placed-in-service
date of the facility for purposes of §45.

     With respect to the seventh issue, the facility was relocated from State D to State

C, and in connection with that relocation it has been represented that all essential
components of the facility were relocated and retained. In the event of relocation of the
facility there should be no change in the placed-in-service date of the facility as long as
the test described in section 5.02 of Notice 2010-54 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 §45(d)(8), relocation of the facility to a different location
after December 31, 2011, will not result in a new placed in service date for the facility for
purposes of §45 provided the fair market value of the used property is more than twenty
percent of the facility’s total value (the cost of the new property plus the value of the
used property) at the time of relocation or replacement.

PLR-109850-15 13

    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 the 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.

  This ruling is directed only to the taxpayer who requested it. Section 6110(k)3) of

the Code provides that 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)