Refined-coal process, facility relocation, and retesting methods approved

Plain-English summary

A taxpayer leased a relocated facility that applied two chemical additives to coal to reduce nitrogen oxide and mercury emissions at a coal-fired power plant. The IRS ruled that the product could be refined coal under section 45 if sold to an unrelated person and if it met the statutory emissions-reduction test. Increasing an additive's application rate would not by itself count as a process change under Notice 2010-54. Leasing the facility after its original placed-in-service date would not reset that date or prevent the lessee from claiming the credit, and relocation or later modification would not create a new date if original property remained more than 20 percent of total facility value. Specified laboratory comparisons could satisfy the six-month emissions redetermination rule when the production process had not changed. The IRS did not decide the facility's actual placed-in-service date, whether an unrelated sale occurred, or whether the taxpayer bore enough production risks and rewards to qualify as the producer.

Ruling snapshot

• Question: Did the additive process, leasing and relocation of the facility, and proposed laboratory retesting satisfy the section 45 refined-coal credit rules?
• Outcome: Approved for the five requested rulings, subject to the stated sales, emissions, value, and testing conditions
• Key authorities: IRC §§ 45, 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: 201533001 Third Party Communication: None
Release Date: 8/14/2015 Date of Communication: Not Applicable
Index Number: 45.00-00
Person To Contact:
------------------------- --------------------------, ID No. ----------------
----------------------------------------- -----------------
-------------------------------------------- Telephone Number:
---------------------- ----------------------
---------------------------------- Refer Reply To:

                                                          PLR-103676-15
                                                          Date:
                                                          May 08, 2015

LEGEND
Taxpayer = -------------------------------------
Company A = ------------------------------------------------------------------
Parent = --------------------------------------------------------------------------------------
Company B = ----------------------------
Company C = ----------------------------------------------
Company D = ----------------------------------------------
Company E = ---------------------------------------
State = --------------
Facility = ------------------------------------------
Date 1 = -------------------
Date 2 = ----------------------------
Date 3 = ---------------------------
Date 4 = ------------------------
Year 1 = -------
Year 2 = -------
Power Plant 1 = ------------------------
Power Plant 2 = -----------------------------
Location 1 = ------------------------------
Location 2 = -----------------------------------------------------------------
X = ----------------
Y = ---------
Coal Type 1 = -------------------------------
Coal Type 2 = -----------------------------------------
Coal Type 3 = --------------------
Coal Type 4 = ----------
Additive A = ---------------
Additive B = ----------------
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a = -----
b = ----
c = ----
d = ----
e = ----
f = ----

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

This is in response to your request for a ruling, submitted by your authorized

representative on January 21, 2015, concerning the federal income tax consequences
of the transaction described below.

FACTS

Taxpayer has represented the facts to be as follows:

Taxpayer Information

Taxpayer is a State limited liability company that is a wholly owned subsidiary of

Company A. Taxpayer was formed to lease and operate the Facility. Because
Taxpayer has not elected to be a classified as an association taxable as a corporation
for federal income tax purposes, it is disregarded as an entity separate from Company A
for such purposes. Company A, a State limited liability company is indirectly wholly
owned by Parent, a State corporation that is the common parent of a consolidated
group. Parent uses the accrual method of accounting and has adopted the calendar
year as its annual accounting period.

The Refined Coal Production Process

A. The Facility

Taxpayer has entered into an agreement to lease the Facility from Company B for

an initial term beginning on Date 2, and ending on Date 3, with automatic renewals for
five successive one-year periods, and a final renewal period ending on Date 4 (Facility
Lease). Company B is wholly owned by Company C. The Facility was designed and
constructed by Company C to produce a refined coal product that reduces emissions of
nitrous oxide (NOx) and mercury when burned as a fuel in a coal-fired power plant.

The Facility was placed in service in Year 1 at the Power Plant 1 in Location 1 that is
owned by Company D. In Year 2, the Facility was relocated to the Power Plant 2 in
Location 2, which is also owned by Company D. The Facility was installed at Location 2
on a new X and with new Y.
 3
PLR-103676-15

The Power Plant 2 is a coal-fired and steam-powered electric generating plant in

regular commercial operation. The Power Plant 2 uses three cyclone coal-fired boilers
to produce electricity by burning Coal Type 1 in the boilers to heat water and produce
steam. The Coal Type 1 burned in the Power Plant 2 is obtained from several local
mines. Taxpayer has entered into a contract with Company D for the sale of refined
coal produced by the Facility to Company D for use as a feedstock in the Power Plant 2.

B. The Process

The technology employed to produce the refined coal in the Facility is known as the

Process, which is designed to reduce NOx and mercury emissions in cyclone coal-fired
boilers. The rights to the technology are owned by Company C. Taxpayer has licensed
those rights from Company C for the full term of its Facility Lease with Company B.

The Process involves the use of two separate inorganic chemicals (the “Chemical

Additives”) that are applied to feedstock consisting of a% Coal Type 1. The first
Chemical Additive, referred to as Additive A, is a solid material that mixes evenly with
the coal’s native ash in power plant boilers and affects the melting properties of the
coal’s native ash during combustion in power plant boilers. This allows adjustment of
stoichiometric, or air-fuel, ratio in the boiler which reduces oxygen and provides more
favorable conditions for reduction of NOx emissions. The second Chemical Additive,
referred to as Additive B, is an inorganic liquid solution which reacts with the mercury in
coal, resulting in changes to the chemical form of the mercury, oxidizing more of it. As a
result, more of the mercury is captured with the fly-ash in the particulate control
equipment, resulting in a higher degree of removal.

The Facility’s equipment transports the Chemical Additives to a coal conveyor belt,

where they are applied evenly to the coal feedstock. The Chemical Additives are
combined with the coal at a rate proportional to the coal flow rate. The application of
each Chemical Additive is controlled separately by computer equipment which
determines the rate of application based on the flow rate of the coal on the conveyor
belt. The minimum proportion of each Chemical Additive to be applied per ton of
feedstock coal is set based on previously verified emissions test results. The amount of
each Chemical Additive applied per ton of feedstock coal may be increased above, but
will not be decreased below, the per-ton amounts of such Chemical Additives used to
produce the refined coal used in the most recent emissions testing.

Emissions Testing

A. Prior Emissions Testing

In Date 1, before the effective date of the Facility Lease, Company C conducted full-

scale emissions tests, using continuous emission monitoring system (CEMS) field
testing at the Power Plant 1, using coal feedstock consisting of approximately b% Coal
 4
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Type 2 and c% Coal Type 3, and refined coal produced at the Facility from the same
coal feedstock. After relocating the Facility to the Power Plant 2 in Year 2, Company C
conducted emissions tests using CEMS field testing at the Power Plant 2 using coal
feedstock consisting of a% Coal Type 1 and refined coal produced at the Facility from
the same coal feedstock.

Each emissions test was conducted in the following manner: To establish a baseline

for NOx and mercury emissions, one unit of the Power Plant 1 or Power Plant 2, as
applicable, was operated for a three-hour period at or above d% of full load using coal
feedstock. The same unit was operated for a second three-hour period under the same
operating conditions (except for adjustments to primary or secondary air in accordance
with good air pollution control practices), using refined coal produced in the Facility from
same coal feedstock.

During each baseline test and each test using refined coal, NOx and mercury

emissions were measured using CEMS equipment that conforms to applicable United
States Environmental Protection Agency (“EPA”) standards. The NOx CEMS devices
were located upstream of post-combustion NOx emissions controls. The mercury
CEMS devices were located upstream of any sulfur dioxide (SO2) scrubber or mercury
control device and downstream of the electrostatic precipitator (ESP), which controls
particulate emissions. Each CEMS field test demonstrated a reduction in excess of e%
of NOx emissions and a reduction in excess of f% of mercury emissions when burning
refined coal produced in the Facility (excluding dilution caused by materials combined or
added during the production process) when compared to emissions resulting from
burning feedstock coal to produce the same amount of useful thermal energy.

Taxpayer represents that the emission reductions demonstrated in each CEMS field

test have been verified by an independent licensed professional engineer experienced
in combustion and environmental engineering, as required by Notice 2010-54, 2010-40
I.R.B. 403 (the Notice), including verification that the ESP was operated under the same
conditions throughout the test period.

B. Redetermination Testing

Taxpayer will conduct additional emissions tests on or before the first to occur of: (i)

a change in the Process used to produce refined coal at the Facility, (ii) a change in the
source or rank of the feedstock coal used to produce refined coal, or (iii) the expiration
of six months since the most recent determination test. If additional testing is conducted
due to a change in the Process, Taxpayer will use a testing methodology permitted by
section 6.03 of the Notice or any subsequent applicable IRS guidance (“Determination
Test”). Taxpayer anticipates that where there has been no change in the Process, it will
ordinarily conduct redetermination testing using 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 (10%) below the bottom (nor by more than ten
 5
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percent (10%) above the top) of the range of the sulfur and the mercury content of the
feedstock coal and refined coal used in the most recent Determination Test period.

C. Additive Rate Tests

Parent retained Company E, an independent engineering firm with recognized

expertise in coal and emissions from coal-fired power plants, to advise Parent with
respect to the effect of increasing the concentration of chemical additives applied in the
refined coal production process on the level of emissions reductions. Company E
reviewed the results of CEMS emissions testing conducted at five different power plants
using refined coal produced from Coal Type 2, Coal Type 4, and blends of Coal Type 1
and Coal Type 2. The refined coal used in the tests was produced in refined coal
production facilities leased by subsidiaries of Parent from Company C by applying the
chemical additives in various concentrations. Based on Company E’s review of those
test results, Company E concluded that neither the NOx emission reduction nor the
mercury emission reduction is adversely affected by applying more chemical additives
to feedstock coal than necessary to achieve the emission reductions, and that
increasing chemical additive application rates generally provides greater emissions
reductions.

RULINGS REQUESTED

Based on the foregoing, Taxpayer has requested that we rule as follows:

1) Refined coal produced at the Facility using the Process and the Chemical
Additives is “refined coal” within the meaning of section 45(c)(7) of the Internal
Revenue Code of 1986, as amended (the “Code”), provided the refined coal (i) is
sold to an unrelated person within the meaning of § 45(c)(7) and (ii) meets the
emission reduction requirement of § 45(c)(7)(B).

2) An increase in the rate of application of a Chemical Additive per ton of feedstock
coal refined is not considered a “change in the process of producing refined coal
from feedstock coal” for purposes of section 6.04 of Notice 2010-54.

3) The lease 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 and will not affect
the determination of whether the lessee is eligible for production tax credits
(“PTCs”) for refined coal produced at the Facility.

4) If the Facility was “placed in service” prior to January 1, 2012, within the meaning
of § 45(d)(8)(B), a subsequent relocation and replacement of certain parts of the
Facility in Year 2, and any subsequent relocation or modification of the Facility,
will not result in a new placed-in-service date for the Facility for purposes of
 6
PLR-103676-15

   § 45, provided the fair market value of the original property of the Facility is more
   than twenty percent (20%) of the Facility’s total fair market value at that time.

5) 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 (10%) below the bottom, or by more than ten percent (10%)
above the top, of the range of the sulfur and the mercury content of the feedstock
coal and the refined coal used in the most recent test conducted pursuant to
section 6.03 of Notice 2010-54.

LAW AND ANALYSIS

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, section 3.01 of the Notice provides that the term "refined coal"

means a fuel which -- (i) is a liquid, gaseous, or solid fuel (including feedstock coal
mixed with an additive or additives) produced from coal (including lignite) or high carbon
fly ash, including such fuel used as a feedstock, (ii) is sold by the taxpayer with the
reasonable expectation that it will be used for purpose of producing steam, and (iii) is
certified by the taxpayer as resulting (when used in the production of steam) in a
qualified emission reduction. Section 45(c)(7) and section 3.04 of the Notice provide
that the term "qualified emission reduction" means (1) in the case of refined coal
produced at a facility placed in service after December 31, 2008, a reduction of at least
twenty percent (20%) of the emissions of nitrogen oxide and at least 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; 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 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.
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Section 5.01 of the Notice provides that the refined coal credit is allowed for qualified

refined coal produced and sold to an unrelated person by the taxpayer, without regard
to whether the taxpayer owns the refined coal production facility in which the refined
coal is produced. Accordingly, a taxpayer that leases or operates a facility owned by
another person may claim the credit for refined coal that the taxpayer produces in the
facility.
Section 5.02 of the Notice provides that a refined coal production facility will not be
considered to have been placed in service after October 22, 2004, if more than twenty
percent (20%) of the total fair market value of the facility (the cost of the new property
plus the value of the used property) is attributable to property that was placed in service
on or before October 22, 2004.

Section 6.01 of the Notice 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) 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 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; (v) a qualified individual verifies the test results in a manner that satisfies the
requirements of section 6.03(1)(b).
 8
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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 emissions reduction. If a method other than CEMS field
testing is used, the Service may require the taxpayer to provide additional proof that the
emission reduction has been achieved. The permissible methods include (a) testing
using a demonstration pilot-scale combustion furnace if it established that the method
accurately measures the emission reduction that would be achieved in a boiler
described in section 6.03(a)(a)(i) and a qualified individual verifies the test results in a
manner that satisfies the requirements of section 6.03(1)(c)(i), (ii), (v), and (vi) of the
Notice; and (b) a laboratory analysis of the feedstock coal and the refined coal that
complies with a currently applicable EPA or ASTM standard and is permitted under
section 6.03(2)(b)(i) or (ii) of the Notice.

Section 6.04(1) of the Notice provides that a taxpayer may establish that a qualified

emission reduction determined under section 6.03 applies to production from a facility
by a determination or redetermination that is valid at the time the production occurs. A
determination or redetermination is valid for the period beginning on the date of the
determination or redetermination and ending with the occurrence of the earliest of the
following events: (i) the lapse of six months from the date of such determination or
redetermination; (ii) a change in the source or rank of 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 or mercury 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 or mercury
content of the amount of feedstock coal necessary to produce the same amount of
useful energy, excluding any dilution caused by materials combined or added during the
production process; or (b) the sulfur or mercury content of both the feedstock coal and
the refined coal do not vary by more than ten percent (10%) 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 the Notice.

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

3.01(1)(c) 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
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CEMS field testing was used to determine the emissions reduction; (3) if CEMS field
testing was not used to determine the emissions reduction, a description of the method
used; (4) a statement that the emissions reduction was determined or redetermined
within the six months preceding the production of the fuel and that there have been no
changes in the source or rank of feedstock coal used or in the process of producing
refined coal from the feedstock coal since the emissions reduction was determined or
was most recently determined; and (5) a declaration signed by the taxpayer in the
following form: “Under penalties of perjury, I declare that I have examined this
certification and to the best of my knowledge and belief, it is true, correct, and
complete.”

Finally, § 45(d)(8) provides that a refined coal production facility must be placed in

service within certain timeframes. For purposes of the refined coal credit allowable with
respect to refined coal other than steel industry fuel, the facility must be placed in
service after October 22, 2004 and before January 1, 2012. Section 3.07 of the Notice
provides that the year in which property is placed in service is determined under the
principles of § 1.46-3(d) of the regulations (i.e., when the property is placed in a
condition or state of readiness and availability for a specifically assigned function).
Section 5.02 of the Notice provides that a refined coal production facility will not be
treated as placed in service after October 22, 2004 if more than 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 two rulings requested, the Process involves blending coal

with the Chemical Additives in a cyclone coal-fired boiler. 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, § 6.01(2) 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 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. Accordingly, we conclude that (a) refined coal produced at the Facility
using the Process and the Chemical Additives is “refined coal” within the meaning of
§ 45(c)(7), provided the refined coal (i) is sold to an unrelated person within the
meaning of § 45(c)(7) and (ii) meets the emission reduction requirement of
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§ 45(c)(7)(B); and (b) an increase in the rate of application of a Chemical Additive per
ton of feedstock coal refined is not considered a “change in the process of producing
refined coal from feedstock coal” for purposes of section 6.04 of the Notice.

With respect to the third ruling requested, 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. Section 5.01 of the Notice
provides that the refined coal credit is allowed for qualified refined coal produced and
sold to an unrelated person by the taxpayer, without regard to whether the taxpayer
owns the refined coal production facility in which the refined coal is produced.
Therefore, a taxpayer that leases or operates a facility owned by another person may
claim the credit for refined coal that the taxpayer produces in the facility. Accordingly,
we conclude that the lease 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 and will not
affect the determination of whether the lessee is eligible for PTCs for refined coal
produced at the Facility.

With respect to the fourth ruling requested, § 45(d)(8) generally provides that a

“refined coal production facility” means a facility for the production of refined coal that
was placed in service after October 22, 2004, and before January 1, 2012. Section 5.02
of the Notice provides that when a facility is placed in service is determined in
accordance with § 1.46-3(d) of the regulations. In addition, section 5.02 of the Notice
provides that a refined coal production facility will not be considered to have been
placed in service after October 22, 2004, if more than twenty percent (20%) of the total
fair market value of the facility (the cost of the new property plus the value of the used
property) is attributable to property that was placed in service on or before October 22,
2004. This rule provides a test for determining whether modifications to a facility will
result in a new placed in service date. Accordingly, we conclude that if the Facility was
“placed in service” prior to January 1, 2012, within the meaning of § 45(d)(8)(B), a
subsequent relocation and replacement of certain parts of the Facility in Year 2, and any
subsequent relocation or modification of the Facility, will not result in a new placed-in-
service date for the Facility for purposes of § 45, provided the fair market value of the
original property of the Facility is more than twenty percent (20%) of the Facility’s total
fair market value at that time.

With respect to the fifth ruling requested, section 6.04(2) of the Notice provides, in

part, that in the case of a redetermination required because of a change in the process
of producing refined coal from the feedstock coal, the redetermination required under
section 6.04 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 ten percent (10%) 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
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redetermination requirement of section 6.04 of the Notice may be satisfied by laboratory
analysis establishing that the sulfur and mercury content of both the feedstock coal and
the refined coal, on average, do not vary by more than ten percent (10%) below the
bottom, or by more than ten percent (10%) above the top, of the range of the sulfur and
mercury content of the feedstock coal and refined coal used in the most recent CEMS
field test or other test that meet the requirements of section 6.03 of the Notice.

This ruling expresses no opinion regarding any issue not specifically addressed in

this ruling letter, including (1) whether any person has sold refined coal to an unrelated
person, or (2) when the facility was “placed in service.” In particular, we express or
imply no opinion that Taxpayer has sufficient risk or rewards of the production activity to
qualify as the producer of the refined coal. The Service may challenge an attempt to
transfer the credit to a taxpayer who does not qualify as a producer, including transfers
structured as partnerships, sales or leases that do not also transfer sufficient risks and
rewards of the production activity.

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

copy of this letter to your authorized 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)