PLR 1320003: IRS approves refined-coal credit treatment and testing methods

Plain-English summary

The IRS considered a partnership's planned production and sale of refined coal treated with chemical additives to reduce emissions. It ruled that the product could qualify as refined coal under IRC § 45 if it used feedstock coal matching the tested source or rank and satisfied the required emissions reduction test. The IRS also approved the taxpayer's proposed pilot-scale testing, source and rank treatment, laboratory redetermination method, late delivery of test reports within stated limits, and treatment of certain facility relocations or component replacements. The ruling did not decide whether the taxpayer sold to an unrelated person, when the facility was placed in service, or whether the taxpayer bore sufficient production risks to qualify as the producer.

Ruling snapshot

• Question: Do the proposed refined-coal process, emissions tests, redeterminations, and facility changes satisfy the requirements for the § 45 credit?
• Outcome: Approved
• Key authorities: IRC §§ 45 and 613; Notice 2010-54; Treas. Reg. § 1.46-3

Full text (IRS public release)

Internal Revenue Service Department of the Treasury
Washington, DC 20224

Number: 201320003 Third Party Communication: None
Release Date: 5/17/2013 Date of Communication: Not Applicable
Index Number: 45.00-00
Person To Contact:
------------------------, ID No. --------------
------------------------ Telephone Number:
----------------------------------- ----------------------
------------------------------------- Refer Reply To:
-------------------------------- CC:PSI:B6
PLR-129662-12
Date:
February 06, 2013

LEGEND:
Taxpayer = ----------------------------------

Investor = ---------------------------------------------
Parent = -----------------------------------------------
Business A = ------------------------
Company A = ---------------------------------------
Company B = ---------------------------------------
Company C = ---------------------------------
Company D = ------------------------------------
Company E = ----------------------------------
Individual A = --------------------
Individual B = ------------------------
Individual C = -------------------
Individual D = -----------------------
Utility = ---------------------------------------
Licensor = -----------------------
State A = --------------
State B = -------------
State C = ---------------------
State D = --------------
State E = -------------------
State F = -------------------
Plant = --------------------------------------
Date 1 = -------
Date 2 = -------
Date 3 = ----------------------
Date 4 = ---------------------------
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Date 5 = ---------------------
Date 6 = ----------------------------
Date 7 = -----------------
Date 8 = ------------------
Date 9 = ----------------------------
Date 10 = ----------------------
Additive 1 = ----------------------
Additive 2 = ------------------------
Center = ------------------------------------------------------------------------------------------
-----------
Test Rep 1 = ------------------------------------------------------------------------------------------
----------------------------
Test Rep 2 = -----------------------------------------------------------------------------------------
----------------------
source region A = ----------------------------
source region B = ------------------------------
x% = ------
y% = ------

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.

FACTS

   Taxpayer, a State A limited liability company calendar year taxpayer employs the

accrual method of accounting for both book and tax purposes and is treated as a
partnership for federal income tax purposes. The members of Taxpayer are Investor
and Company A, a State A limited liability company. The ultimate principal owners of
Company A are Individual A, Individual B, Individual C and Individual D. Those
individuals have worked and invested together in various projects since at least Date 1.
Some of their prior projects included the development, construction and operation of
synthetic fuel production facilities and waste coal processing facilities. Commencing in
Date 2, the principals agreed to develop a new refined coal business, including that
conducted by Taxpayer.

   Investor is a State A limited liability company and wholly owned, indirect

subsidiary of Parent, a publicly traded State A corporation that is primarily engaged
through its subsidiaries in Business A. Investor is classified as an association taxable
as a corporation for U.S. federal tax purposes.
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    Taxpayer was organized on Date 3 to construct a facility for the production of

refined coal that was placed in service at a mine site in State B on or about Date 4 and
produced and sold refined coal with the expectation that it would be burned to produce
steam. However, due to unforeseen difficulties in identifying customers willing to enter
into long-term contracts to purchase refined coal, Taxpayer did not continue producing
refined coal after Date 5.

   Subsequently, on Date 6, Taxpayer entered into contracts with Utility, as

described below, to locate a refined coal production facility on a site adjacent to the
Plant in State C, and to sell refined coal produced in that facility to Utility. Because its
existing facility did not meet the functional requirements for producing refined coal at
this new location, Taxpayer arranged for the construction of a new facility and assigned
the original facility to Company C. No portion of the original facility was used to
construct the new facility.

   In anticipation of the transaction with Investor described below, the Initial

Members undertook a reorganization of Taxpayer on Date 7. Pursuant to that
reorganization, the membership interests in Taxpayer were recapitalized into class A
and class B interests. The class A interests were contributed to Company A and the
class B interests were contributed to Company B. Subsequently, the interests in
Company B were contributed to Company C, which then contributed such interests to
Company D. Each of Company A and Company C are classified as partnerships, and
each of Company B and Company D are disregarded as separate entities from
Company C.

    On Date 8, Investor acquired all of the class B membership interests in Taxpayer

from Company B in a transaction treated as a taxable sale or exchange of an interest in
a partnership for U.S. federal income tax purposes. Simultaneously, Investor and
Company A entered into a limited liability agreement with respect to Taxpayer, setting
forth their agreement regarding the respective rights and obligations of the class A and
class B interest in Taxpayer, the management and related decision-making of Taxpayer,
and certain related matters.

     Pursuant to its agreements with Utility, Taxpayer purchases coal feedstock from

Utility. The coal supply agreement does not prohibit Taxpayer from purchasing coal
feedstock from third parties, and does not prohibit Taxpayer from purchasing more
feedstock coal than the Utility would expect to buy from Taxpayer in the form of refined
coal.

     The feedstock coal purchased by Taxpayer typically is coal that the Utility itself

purchased from third party vendors, consistent with its coal specifications. Taxpayer
uses the Process (as described below) to produce refined coal that it sells to the Utility
pursuant to a refined coal sales agreement. All of the refined coal produced in the
facility is expected to be used as a fuel at the Plant to produce steam for the generation
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of electricity. However, any refined coal not purchased by Utility can be sold to one or
more third parties.

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

maintenance agreement with Company E, a State A limited liability company and
affiliate of Company A. Pursuant to that agreement, Company E 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. In addition, Company E will arrange for
testing of refined coal as described below.

    The facility is capable of being relocated without affecting its capability to

produce refined coal. In the future, the facility may be disassembled and relocated to
another location. Such relocations of refined coal facilities are a routine exercise that
can be accomplished with only limited duplication of certain common equipment and
civil works and foundations, which are relatively minor in the context of these projects.
In the event of any relocation of the facility, all of the essential components of the facility
will be relocated and retained.

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 owned by Licensor and is
licensed to Taxpayer. 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 the 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. A by-product of the Process is a valuable fly ash that can be used in a diverse
array of applications in the steel, mining and cement industries.

Emissions Reduction Testing

    For purposes of determining emissions reductions under § 45, Taxpayer 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. Taxpayer engaged the research center of a prominent university (the
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Center) to conduct tests on behalf of Taxpayer at its pilot-scale combustion test facility
(CTF) to determine the emission reductions associated with burning the refined coal
compared to the feedstock coal. 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 (pc)-fired boilers.

For purposes of qualifying the refined coal produced at the facility, Center conducted
pilot-scale combustion tests at its CTF on Date 9 on a blend of feedstock coal consisting
of x% source region A coal and y% source region B coal, which blend represented the
anticipated blend to be used at the Plant. More recently, on Date 10, the Center
conducted another pilot-scale combustion test at its CTF on a similar blend for purposes
of determining the appropriate application rates for the subsequent six month period.

   Each of Test Rep 1 and Test Rep 2 explains that combustion gas analysis is

provided by continuous emissions 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.
Center conducted a series of tests on the feedstock and refined coal blend, measuring
the emissions with these devices.

     Each of Test Rep 1 and Test Rep 2 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. Each report also states
that it is expected the emissions reduction reported would be achieved at full scale
using the additive levels tested.

Tested Coal

   Plant currently burns a blend of bituminous coal from a number of mines located

in State D, State E, and State F, within source region A and source region B. The
Partnership produces refined coal using a blend of these coals and sells that refined
coal to Plant which burns it to generate electricity from steam. The rank of the coal
burned at the Plant is classified by the American Society of Testing Materials (ASTM) as
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bituminous coal with a gross calorific value of 12,200 to 13,000 btu/lb. Variations in the
coal blend result from the supply and availability of the coals and the needs of the Plant.

   Taxpayer requested that Center test a blend of coal that represents the range of

coal blends to be used at the Plant (the “Tested Coal”). The report issued by Center
states that the emission reduction requirements outlined in § 45 for NOx and mercury
were satisfied when comparing the results of burning the endpoint fuel to the results of
burning the feedstock coal.

   Taxpayer expects to continue to operate with the blend and additive levels

discussed in the Center reports, which would be consistent with long-term patterns for
coal consumed at the 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 will be collected and
prepared in accordance with sampling and testing procedures set forth in Taxpayer’s
operating protocols. Although testing and preliminary reporting is done timely,
occasionally the Center is not able to issue the final report until after the six-month
period.

    Although Taxpayer 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. 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 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 Notice
2010-54, regardless of the mines from which such feedstock coal is purchased.
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   3. Testing by Center for qualified emissions reduction as set forth in its test

reports satisfies the requirements of Notice 2010-54. Pilot scale testing conducted at
Center (and subsequent permitted laboratory testing as required for a redetermination
described in section 6.04(2)(a) or (b) of Notice 2010-54) may be relied upon 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 redetermination

requirement of section 6.04 of Notice 2010-54 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 ten percent from the sulfur and
mercury content of the feedstock coal and the refined coal used in the most recent
determination that meets the requirements of section 6.03 of Notice 2010-54.

   5. The results set forth by the Center in a redetermination test report for

production may be relied upon 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. 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, or replacement of part of a facility after that date, 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 total fair market value of the
relocated facility 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
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twenty percent (20%) of the emissions of nitrogen oxide and at least forty percent (40%)
of the emissions of either sulfur dioxide or mercury released when burning the refined
coal (excluding any dilution caused by materials combined or added during the
production process), as compared to the emissions released when burning the
feedstock coal or comparable coal predominantly available in the marketplace as of
January 1, 2003.

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

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

    Section 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).
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     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) 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
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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 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
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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
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 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, 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 its CTF 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 CTF as documented in Test Rep 1 and
Test Rep 2. 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 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
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
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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 Notice 2010-54 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 from 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 Notice 2010-54.

    With respect to the fifth issue, it is intended that redetermination testing will occur

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. 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 Notice 2010-54, so long as the written report is received
within 90 days from the date of testing. The new six month period will begin on the date
the redetermination was completed not the date of receipt of the report.

     With respect to the sixth issue, we understand that the facility may be relocated

to another location in the future. In that case, all of the essential components of the
facility will be relocated and retained. Similarly, during the life of the facility, it may be
necessary to replace certain major components. In the event of relocation or
replacement of a component, there should be no change in the placed in service date of
the facility as long as the test described in section 5.02 of 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, 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
§45 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 about 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 risks and 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
 13
PLR-129662-12

transfers structured as partnerships 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 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)