Refined coal process and testing support production tax credit

Plain-English summary

A partnership operated a facility that mixed coal with chemical additives intended to reduce nitrogen oxide and mercury emissions. It asked whether the product qualified as refined coal for the section 45 production tax credit and whether its testing and redetermination methods were acceptable. The IRS ruled that the additive process could produce qualifying refined coal if the statutory emissions test and unrelated-person sale requirements were met. It also approved treating coal from the same region and rank as the same source, relying on pilot-scale combustion testing, and using specified laboratory analysis for later six-month redeterminations. A later ownership change would not alter the facility's placed-in-service date, although the ruling did not decide whether the taxpayer was the producer, whether an unrelated sale occurred, or when the facility was actually placed in service.

Ruling snapshot

• Question: Did the refined-coal process, coal sourcing, testing methods, and ownership history satisfy the requested section 45 credit rules?
• Outcome: Approved on the stated facts and conditions
• Key authorities: IRC §§ 45(c)(7), 45(d)(8), 45(e)(8), and 613(c); Treas. Reg. § 1.46-3(d); Notice 2010-54

Full text (IRS public release)

Internal Revenue Service Department of the Treasury
Washington, DC 20224

Number: 201510026 Third Party Communication: None
Release Date: 3/6/2015 Date of Communication: Not Applicable
Index Number: 45.00-00
Person To Contact:
-------------------------- -------------------------, ID No. -----------------
------------------------------ ----------------------------------------------------
---------------------------------- Telephone Number:
------------------------------ --------------------
-------------------------- Refer Reply To:
CC:PSI:B06
PLR-120241-14
Date:
November 12, 2014

LEGEND
Taxpayer = ---------------------------------------------------------
Company A = -------------------------------------
Company B = -----------------------------------------------
Company C = ----------------------
Developer = --------------------------------------------
Licensor = -------------------------------------
Sub = -------------------
Parent = ---------------------------------
State A = ------------
State B = --------
Year = ------
Power Plant = ------------------------------------------
Location 1 = --------------------
Location 2 = ----------------
Date 1 = --------------------------
Date 2 = -------------------------
Date 3 = ------------------
Additive 1 = -----------------------------------------------
Additive 2 = --------------------------------------
Unit A = ----------
Unit B = ---------
a= ---
b= --
c= -------
d= -------
e= -------
f= -------
Research Center = --------------------------------------------------------
------------------------------------
Test Report A = -----------------------------------------------------------------------------------------
Test Report B = ------------------------------------------------------------------------------------------
PLR-120241-14 2

                 -------------------------------------------------------------------------------------

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

  This letter is in response to your request for rulings, submitted by your authorized

representative on Date 3, concerning the federal income tax consequences of the
transaction described below.

FACTS

Taxpayer represents the facts as follows:

Taxpayer Information

  Taxpayer is a State A limited liability company treated as a partnership for federal

income tax purposes. Taxpayer was formed in Year to own, manage, and operate a
number of refined coal ventures in cooperation with strategic partners.

    Company A is a State A limited liability company treated as a partnership for

federal income tax purposes that is owned a percent by Taxpayer and b percent by
Licensor. Company A was formed by Developer to own the refined coal facility (Facility)
located at an electric utility generating station (Power Plant) owned by Company B in
Location 1. The Facility uses clean coal technology licensed from Company C
(Technology) to reduce air emissions from burning coal (primarily nitrogen oxide (NOX),
mercury (Hg), and metals). Company A produces refined coal at the Facility and sells
the refined coal to Company B to fuel the Power Plant.

   Developer is a State B limited liability company treated as a partnership for

federal income tax purposes that acts as the manager of Taxpayer. Developer
designed, engineered, and constructed seven refined coal facilities to utilize the
Technology, including the Facility.

  Licensor is a State B limited liability company treated as a partnership for federal

income tax purposes. Licensor is the owner of the Technology license for the Facility
and assigned use of that license to Company A.

  Sub is a State A corporation treated as a corporation for federal income tax

purposes that is a wholly-owned subsidiary of Parent. Parent is an investor in and
member of Company C, owner and developer of the Technology.

    On Date 2, Developer sold a a percent membership interest in Taxpayer to Sub.

After the transaction, Taxpayer is owned by Sub as a a percent member, and by
Developer, as a b percent member and manager.
PLR-120241-14 3

The Refined Coal Facility

    The Facility was originally placed in service by Developer at the Power Plant on

Date 1. The Facility has continually operated at the Power Plant since it was placed in
service and has never been removed or relocated from the Power Plant. Developer
installed chemicals storage facilities adjacent to the Power Plant that are also owned by
Company A.

   The Facility consists of two refined coal mixer units, Unit A and Unit B, which

receive utility-grade coal at the Power Plant and thoroughly blend the coal with the
Technology. Unit A produces refined coal for a cyclone boiler in the Power Plant, and
Unit B produces refined coal for a circulating fluidized bed boiler in the Power Plant.
The basic design of each mixer unit within the Facility is as follows:

1) Coal and the Technology additives are fed into a blend chamber at the end of a
coal belt conveyor where there is sufficient elevation to allow the coal mixture
(feedstock coal plus chemicals) to enter the top of the blend chamber.

2) The Technology additives are metered onto the coal while the coal is in a
suspended state as it enters the chamber. At this point, the coal is in a thin layer
which assists in assuring uniform blending of the separate components. The
momentum of the falling thin layer of coal, now containing the additives, propels
the mixture into an impact plate in the blend chamber, creating a violent action
that instantaneously comingles the chemicals and coal. The impact of the
comingled mixture changes the direction of the flow and directs the mixture down
further into the chamber.

3) At this point the mixture is then struck by paddles (generally rectangular pieces of
hardened steel) attached to a drum which rotates continually inside the chamber
to provide further blending.

4) The drum rotation channels the mixture to the bottom opening of the chamber
onto a screen and conveyor below the chamber where the product is further
sized as necessary and then conveyed to bunkers that feed the Power Plant
steam boilers.

The Technology

  The Technology is a patented process for injection of two chemical sorbents to

modify utility-grade coal. The two chemical additives are Additive 1 and Additive 2.
These additives reduce emissions of NOX, mercury (Hg), and other metals when mixed
PLR-120241-14 4

with the coal at the proper ratios prior to combustion in a boiler furnace.

   The Technology provides the chemical structure to create a “ceramic matrix”

using chemical bonds to capture emissions of regulated pollutants. The matrix has a
certain structure of chemicals in certain positions. At the interior corners of the matrix,
the structure will pick up and hold pollutants such as mercury (Hg), arsenic (As), or lead
(Pb). The structure also picks up and includes elements such as oxygen, chlorides and
fluorides, which are freely available in a boiler’s gas stream when they have been
released from the coal during combustion but become locked up in the ceramic matrix.
As the gas stream starts to cool, the chemical bonds form into a very strong matrix.
Because the matrix was created under extremely high temperatures, it can only be
broken at similar temperatures.

   When coal is burned, mercury (Hg) and many other metals are vaporized in the

combustion process and are emitted into the atmosphere with the flue gas. The
Technology captures mercury (Hg) and other metals in the coal ash, thereby eliminating
them from the flue gas before the flue gas exits the boiler stack. The mercury (Hg) and
other metals instead remain entrapped into the ash in a non-leachable form for safe
disposal.

    Also, coal combustion produces NOX as the fuel is burned under oxidizing

conditions. The levels of NOX produced are a function of many factors including excess
air, fuel nitrogen content, flame temperature, burner configuration, and combustion air
staging. Nitrogen oxides can also be affected by ambient air temperatures. The
Technology provides NOX reductions via several mechanisms, which include a slight
reduction of flame temperature, adsorption of NOx species, and chemical capturing of
NOX species. The primary mechanism appears to involve adsorption and capture of
NOX species within the altered fly ash. This results in a significant reduction in the NOX
species that are released into the air.

Emissions Reduction Testing

    The feedstock coal used in the Facility (Tested Coal) was tested at the Research

Center. The Research Center is a high-tech, nonprofit branch of a prominent university
that is widely recognized as a leader in developing cleaner, more efficient energy and
environmental technologies for preservation of natural resources such as air, soil, and
water.

   Both Unit A and Unit B of the Facility refine bituminous coal from different

suppliers in the Location 2 region, including newly mined coal and coal fines recovered
from State B coal wash plants. Given that this coal is all from the Location 2 region, it is
of the same source or rank as the Tested Coal even though the coal may come from
other mines or wash sites.
PLR-120241-14 5

   The Research Center conducted a series of pilot-scale tests of the Tested Coal

in the Center’s combustion test facility (CTF). The Research Center’s CTF has been
extensively used to research and investigate SOx and NOx emissions, and the
transformation of toxic trace metals (mercury (Hg), arsenic (As), and lead (Pb)) during
the combustion of coal and other fuels. The CTF is capable of producing gas and
particulate samples representative of those produced in industrial and full-scale
pulverized coal-fired boilers, and for testing purposes the facility firing rate may be set
based on a target furnace exit gas temperature simulating the operating parameters of a
specific boiler.

    Separate tests were conducted for the Tested Coal refined by Unit A and Unit B

of the Facility to accurately replicate the boilers supplied with refined coal from these
units. The Tested Coal used in the CTF was considered comparable to coal used at the
Facility to produce refined coal. In each case, the Research Center divided the Tested
Coal into separate untreated samples and samples treated with the Technology
additives at a specified rate.

    The Tested Coal for Unit A was analyzed in the Research Center’s CTF

designed to replicate the combustion of a cyclone boiler, which is the boiler type
supplied by Unit A of the Facility. Test Report A, drafted by the Research Center based
on tests conducted on Unit A using the Tested Coal, 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 in-leakage 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 in-leakage. Flue gas
analyses were obtained from the duct at the outlet of the electrostatic precipitator (ESP).
Flue gas mercury (Hg) measurements were obtained separately by a continuous
mercury (Hg) monitor (CMM) located at the flue gas ducting at the exit of the particulate
control device. The Research Center conducted a series of tests on the Tested Coal
and refined coal blends, measuring the emissions with these devices. The combustion
of the Tested Coal after treatment with the Technology (i.e., refined coal) resulted in the
following reductions in NOx and mercury (Hg) emissions:

Nitrogen Oxides (NOx) Reduction: c percent
Mercury (Hg) Reduction: d percent

   The Tested Coal for Unit B was analyzed in the Research Center’s CTF

designed to replicate the combustion of a fluidized bed combustor, which is the boiler
type supplied by Unit B of the Facility. Test Report B, drafted by the Research Center
based on tests conducted on Unit B using the Tested Coal, explains that combustion
gas analysis is provided by continuous emissions monitors (CEMs) used to measure
flue gases, including NOX, SO2, O2 and CO2 simultaneously at the baghouse outlet and
the primary cyclone outlet. All gas analyses were continuously monitored and recorded
PLR-120241-14 6

by a data acquisition system. The data from the primary cyclone location were recorded
remotely with computer hardware and software specially designed for this purpose. The
baghouse exit analyzers, as well as all other temperatures, pressures, and flows
reported were also measured using specially designed software and hardware devices.
Continuous mercury (Hg) monitors (CMMs) were used to measure mercury (Hg)
concentrations at the baghouse inlet and outlet. The combustion of the Tested Coal
after treatment with the Technology (i.e., refined coal) resulted in the following
reductions in NOx and mercury (Hg) emissions:

Nitrogen Oxides (NOx) Reduction: e percent
Mercury (Hg) Reduction: f percent

   Taxpayer desires to rely on pilot-scale testing, such as the CTF, because

Taxpayer believes it is an accurate methodology of scientifically comparing the
emissions from untreated feedstock coal with the emissions from refined coal treated
with the Technology under consistent baseline operating conditions. Taxpayer
perceives the pilot-scale test to be more reliable than monitoring systems employed at
the Power Plant because of uncontrolled variables at the Power Plant and the inability
to insure that consistent baseline conditions are established for both the burning of
untreated feedstock coal and refined coal.

    In addition, Taxpayer has the ability to measure the sulfur (S) and mercury (Hg)

content of the feedstock coal through laboratory testing. The feedstock coal is shipped
via rail and truck to the Power Plant. The coal delivered to the Power Plant is sampled
and can be tested to determine its sulfur (S) and mercury (Hg) content when it is added
to a coal stock pile at the Power Plant. Thereafter, Taxpayer purchases coal from the
stock pile, processes this feedstock coal into refined coal, and sells the refined coal to
Company B.

    Taxpayer also receives reports of the sulfur (S) and mercury (Hg) content of the

chemical additives that are applied to the feedstock coal. Therefore, Taxpayer may
elect to implement procedures for laboratory testing to determine the sulfur (S) and
mercury (Hg) content of the refined coal. These procedures could involve extrapolation
from the sulfur (S) and mercury (Hg) content of each constituent component of the
refined coal or testing the refined coal in a lab separately to reliably determine the sulfur
(S) and mercury (Hg) content of the refined coal. Accordingly, Taxpayer could employ
such lab testing procedures to assess the average content of sulfur (S) and mercury
(Hg) in the feedstock coal and refined coal in lieu of pilot-scale testing at the Research
Center.

   Taxpayer will continue to conduct pilot-scale tests at the Research Center or

similar reputable testing centers within every six (6) month period of Facility operations
for Unit A and Unit B of the Facility unless Taxpayer determines that the analysis of the
feedstock coal and refined coal used for a given six (6) month period indicates that the
PLR-120241-14 7

sulfur (S) and mercury (Hg) content of both the feedstock coal and the refined coal have
not changed on average by more than ten percent (10%) (plus or minus) from the
Tested Coal in the most recent pilot-scale test. Further, while Taxpayer intends to
schedule pilot-scale tests in compliance with the foregoing, the Research Center may
not always deliver a written report of its CTF test before the expiration of each six (6)
month date, due to the Research Center’s internal procedures for review and
processing of its reports. In such cases, the Research Center has agreed that it will
provide confirmation (generally via email) verifying the results of its CTF testing and will
thereafter deliver the detailed written report upon its completion. Despite the fact that
the final report may be received after a given six (6) month period, Taxpayer intends to
have the actual pilot-scale tests completed and obtain the results of tests within each
applicable six (6) month period which will be properly certified by a qualified
professional engineer at the Research Center.

RULINGS REQUESTED

   1) The refined coal produced by the Facility constitutes “refined coal” within the
      meaning of § 45(c)(7) of the Code and may qualify for credit under § 45(e)(8)
      upon its sale to “unrelated persons” as defined in § 45(e)(4), provided the
      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).

   2) Provided that the feedstock coals used to produce refined coal during any
      determination period are from the same coal source region and are of the
      same rank as the Tested Coal, all feedstock coals that satisfy that criteria
      shall be treated as feedstock coal of the same source and rank for purposes
      of section 6.04 of Notice 2010-54, even though the coals may be from
      different mines in the region.

   3) Testing by the Research Center for qualified emissions reduction as set forth
      in its test report satisfies the requirements of Notice 2010-54. Taxpayer may
      rely on the pilot-scale testing conducted at the Research Center to satisfy the
      qualified emission reduction test of § 45(c)(7)(B), regardless of subsequent
      normal fluctuations in operating conditions and emissions at the Power Plant.

   4) As an alternative to pilot-scale testing every six (6) months, Taxpayer is
      permitted to implement testing procedures to satisfy the redetermination
      requirement of section 6.04 of Notice 2010-54 by laboratory analysis
      establishing that the sulfur (S) and mercury (Hg) content of the feedstock coal
      and refined coal, on average, do not vary by more than ten percent (10%)
      from the sulfur (S) and mercury (Hg) content of the feedstock coal and the
      refined coal used in the most recent determination, in accordance with section
      6.04(2)(b) of the Notice.

PLR-120241-14 8

   5) A change in ownership of the Facility subsequent to its placed-in-service date
      will not affect the placed-in-service date of the Facility for purposes of § 45.

LAW AND RATIONALE

Process and Testing of Refined Coal

    Section 45(a) of the Code generally provides a credit against federal income tax

for the use of renewable or alternative resources to produce electricity or fuel for the
generation of steam. Section 45(e)(8) provides that, in the case of a producer of
“refined coal”, the credit available under § 45(a) 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 to an unrelated person with the reasonable expectation that it will
be used for purpose of producing steam; and (iii) is certified by the taxpayer as resulting
(when used in the production of steam) in a qualified emission reduction. Section 3.04
of the Notice provides that the term “qualified emission reduction” means (1) in the case
of refined coal produced at a facility placed in service after December 31, 2008, a
reduction of at least twenty percent (20%) of the emissions of nitrogen oxide (NOx) and
at least forty percent (40%) of the emissions of either sulfur dioxide (SO2) or mercury
(Hg) 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; and (2) in the case of production at a facility
placed in service before January 1, 2009, a reduction of at least twenty percent (20%) of
the emissions of NOx and at least twenty percent (20%) of the emissions of either SO2
or mercury (Hg) 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 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)(l)) if
performed by the mine owner or operator. Accordingly, in determining whether a
PLR-120241-14 9

qualified emission reduction has been achieved, the emissions released when burning
the refined coal must be compared to the emissions that would be released when
burning the feedstock coal. Feedstock coal is the product resulting from processes that
are treated as mining and are actually applied by a taxpayer in any part of the
taxpayer’s process of producing refined coal from coal.

    Section 613(c)(5) of the Code describes treatment processes that are not

considered as mining unless they are provided for in § 613(c)(4) or any necessary or
incidental to a process provided for in § 613(c)(4). Any cleaning process, such as a
process that uses ash separation, dewatering, scrubbing though a centrifugal pump,
spiral concentration, gravity concentration, flotation, application of liquid hydrocarbons
or alcohol to the surface of the fuel particles or to the feed slurry provided such cleaning
does not change the physical or chemical structure of the coal, and drying to removed
free water, provided such drying does not change the physical or chemical identity of
the coal, will be considered as mining.

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

determined using continuous emission monitoring system (CEMS) field testing. Section
6.03(1)(a) provides, in part, that CEMS field testing is testing that meets all the following
requirements: (i) the boiler used to conduct the test is coal-fired and steam-producing
and is of a size and type commonly used in commercial operations; (ii) emissions are
measured using a CEMS; (iii) if EPA has promulgated a performance standard that
applies at the time of the test to the pollutant emission being measured, the CEMS must
conform to that standard; (iv) emissions for both the feedstock coal and the refined coal
are measured at the same operating conditions and over a period of at least 3 hours
during which the boiler is operating at a steady state at least ninety percent (90%) 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 emissions reduction. If a method other than
CEMS field testing is used, the Service may require the taxpayer to provide additional
proof that the emission reduction has been achieved. The permissible methods include:
(a) testing using a demonstration pilot-scale combustion furnace if it established that the
method accurately measures the emission reduction that would be achieved in a boiler
described in section 6.03(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
PLR-120241-14 10

occurs. A determination or redetermination is valid for the period beginning on the date
of the determination or redetermination and ending with the occurrence of the earliest of
the following events: (i) the lapse of six (6) months from the date of such determination
or redetermination; (ii) a change in the source or rank of feedstock coal that occurs after
the date of such determination; or (iii) a change in the process of producing refined coal
from the feedstock coal that occurs after the date of such determination or
redetermination.

   Section 6.04(2) of the Notice provides that in the case of a redetermination

required because of a change in the process of producing refined coal from the
feedstock coal, the redetermination required under section 6.04 must use a method that
meets the requirements of section 6.03. In any other case, the redetermination
requirement may be satisfied by laboratory analysis establishing that - (a) the sulfur (S)
or mercury (Hg) content of the amount of refined coal necessary to produce an amount
of useful energy has been reduced by at least twenty percent (20%) (forty percent
(40%), in the case of facilities placed in service after December 31, 2008) in comparison
to the sulfur (S) or mercury (Hg) 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 (S) and mercury
(Hg) content of both the feedstock coal and the refined coal do not vary by more than
ten percent (10%) from the sulfur (S) and mercury (Hg) 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.

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

3.01(1)(c) of the Notice is satisfied with respect to fuel for which the refined coal credit is
claimed only if the taxpayer attached to its tax return on which the credit is claimed a
certification that contains the following: (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 (6) months preceding the production of the
fuel and that there have been no changes in the source or rank of feedstock coal used
or in the process of producing refined coal from the feedstock coal since the emissions
reduction was determined or was most recently determined; and (5) a declaration
signed by the taxpayer in the following form: “Under penalties of perjury, I declare that I
have examined this certification and to the best of my knowledge and belief, it is true,
correct, and complete.”

     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.
PLR-120241-14 11

Section 3.07 of the Notice provides that the year in which property is placed in service is
determined under the principles of § 1.46-3(d) of the regulations; i.e., when the property
is placed in a condition or state of readiness and availability for a specifically assigned
function.

    Section 5.02 of the Notice provides that a refined coal production facility will not

be treated a placed in service after October 22, 2004 if more than twenty percent (20%)
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 Facility uses a process, which involves the

application of two chemical additives 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 from NOx and mercury during combustion. Section 6.01 of the Notice
provides generally that a qualified emission reduction does not include any reduction
attributable to mining processes or processes that would be treated as mining, as
further defined in the Code, if performed by the mine owner or operator. Section
613(c)(5) describes certain treatment processes that are not considered as mining
unless they are provided for in § 613(c)(4) or are necessary or incidental to a process
provide for in § 613(c)(4). For example, section 6.01(2) of the Notice provides, in part,
that any cleaning process such as the application of liquid hydrocarbons or alcohol to
the surface of the fuel particle or to the feed slurry, provided such cleaning does not
change the physical or chemical structure of the coal, will be considered mining.

    In the instant case, the process is not a mining process. Further, section 3.01 of

the Notice clarifies § 45(c)(7) and specifically provides that refined coal includes
feedstock coal mixed with an additive or additives. Thus, additive processes which mix
certain chemicals or other additives with the coal in order to achieve emission
reductions may qualify for the production tax credit for refined coal. Additionally, section
3.03 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 refined coal produced by the
Facility constitutes “refined coal” within the meaning of § 45(c)(7) and may qualify for
credit under § 45(e)(8) upon its sale to “unrelated persons” as defined in § 45(e)(4),
provided the 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).

   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 market place as of January 1, 2003. Section 3.03 of the
Notice provides that a “comparable coal” is defined as coal that is of the same rank as
PLR-120241-14 12

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) six (6) months have passed since the date of such
determination or redetermination; (ii) a change in the source or rank of feedstock coal
that occurs after the date of such determination or redetermination; or (iii) a change in
the process of producing refined coal that occurs after the date of such determination or
redetermination.

    In this case, Taxpayer currently purchases all of its coal from mines and wash

plant sites in the Location 2 region and the Location 2 region coal is of the same source
and rank. Accordingly, we conclude that provided that the feedstock coals used to
produce refined coal during any determination period are from the same coal source
region and are of the same rank as the Tested Coal, all feedstock coals that satisfy 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 mine or wash plant site from which
such feedstock coal is purchased.

    With respect to the third and fourth issues, section 6.03(3) of the Notice provides

that any permissible testing method provided for section 6.03 of the Notice can be used
in emission testing for any pollutant. That is, a taxpayer can use different testing
methods for each of NOx, SO2 or mercury (Hg), 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 (6) 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 (6) month period using one or
more approved methods. Section 6.04(2) provides that in the context of
“redetermination” that the redetermination requirement may be satisfied by laboratory
analysis establishing either that (i) the sulfur (S) or mercury (Hg) content of the amount
of refined coal necessary to produce an amount of useful energy has been reduced by
at least twenty percent (20%) (forty percent (40%), in the case of facilities placed in
service after December 31, 2008) in comparison to the sulfur (S) or mercury (Hg)
content of the amount of useful thermal energy, excluding any dilution used by materials
combined or added during the production process; or (ii) the sulfur (S) and mercury (Hg)
content of both the feedstock coal and the refined coal do not vary by more than ten
percent (10%) from the sulfur (S) and mercury (Hg) content of the feedstock coal and
refined coal used in the most recent determination that meets the requirements of the
testing methods for emissions reductions in section 6.03 of the Notice.

   In the instant case, Taxpayer engaged the Research Center to conduct tests at

its CTF to determine the emission reductions associated with burning the refined coal
product compared to the feedstock, which is a permissible method under section 6.04 of
the Notice. For purposes of qualifying the refined coal produced at the Facility, the
PLR-120241-14 13

Research Center conducted pilot-scale combustion tests at its CTF on feedstock coal
burned at the Power Plant as detailed in its Test Report A (results of testing Unit A) and
Test Report B (results of testing Unit B) (collectively the Test Reports). The Research
Center mixed the coal and additives in a manner consistent with the mixing that would
occur at the Facility. In the Test Reports, the Research Center conducted tests on
feedstock and refined coal product samples collected from and produced by the Facility.
In the Test Reports, the Research Center reported that the test results indicated that the
blend of coal and additives achieved the required emissions reductions. The results
detailed in the Test Reports indicated that the refined coal samples achieved the
required emissions reductions.

    Based on the foregoing we conclude that (i) testing by the Research Center for

qualified emission reductions as set forth in its Test Reports satisfies the requirements
of Notice 2010-54. Taxpayer may rely on the pilot-scale testing conducted at the
Research Center to satisfy the qualified emission reduction test of § 45(c)(7)(B)
regardless of subsequent normal fluctuations in operating conditions and emissions at
the Power Plant, and (ii) pursuant to section 6.04(2) 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 (S) and mercury (Hg) content of both the
feedstock coal and the refined coal, on average, do not vary by more than ten percent
(10%) from the sulfur (S) and mercury (Hg) 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 ruling request, § 45(d)(8) provides that a refined coal

facility must be placed in service within certain timeframes. Section 3.07 of Notice
2010-54 provides that the year in which property is placed in service is determined
under the principles of Treasury Regulation § 1.46-3(d); i.e., when the property is placed
in a condition or state of readiness and availability for a specifically assigned function.
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 entity that owns and
operates the facility (and claims the credit for such production) at a later date. The
change in ownership of the Facility subsequent to its placed-in-service date will not
affect the placed-in-service date of the Facility for purposes of § 45.

    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 actually “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 transfers structured as partnerships, sales or leases that do not also
transfer sufficient risks and rewards of the production activity.
PLR-120241-14 14

    In accordance with the Power of Attorney on file with this office, we are sending a

copy of this letter to your authorized representative. 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)

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