Refined-coal processes and emissions testing qualified for section 45 credit rules

Plain-English summary

A taxpayer leased and operated a facility that applied separate chemical-additive processes to coal used in cyclone and pulverized boilers, with the goal of reducing nitrogen oxide and mercury emissions. The IRS ruled that the resulting product could be refined coal under section 45 if it was sold to an unrelated person and met the statutory emissions-reduction test. Increasing an additive's application rate would not by itself be a process change requiring new testing 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 credits, and later modifications or relocation would not create a new date if original property remained more than 20 percent of total value. Qualified pilot-scale combustion testing could establish the required reductions, and specified laboratory comparisons could satisfy later redetermination requirements. The IRS did not decide when the facility was actually placed in service, whether coal was sold to an unrelated person, or whether the taxpayer bore enough production risks and rewards to be the producer entitled to the credit.

Ruling snapshot

• Question: Did the additive processes, facility leasing and modifications, pilot-scale tests, and laboratory redeterminations satisfy the section 45 refined-coal credit rules?
• Outcome: Approved for the six 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: 201533002
Third Party Communication: None
Release Date: 8/14/2015
Date of Communication: Not Applicable
Index Number: 45.00-00
Person To Contact:
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--------------------------, ID No. ----------------
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-------------------------------------------- Telephone Number:
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Refer Reply To:
CC:PSI:B06
PLR-103678-15
Date:
May 08, 2015

LEGEND:
Taxpayer = -------------------------------------------
Company A = ------------------------------------------------------------------
Parent = --------------------------------------------------------------------------------------
Company B = ------------------
Company C = ----------------------------------------------
Company D = -------------------------------------------------------
Company E = -------------------
Company F = ---------------------------------------
State = --------------
Facility = ------------------------------------------
Date 1 = --------------------
Date 2 = --------------------
Date 3 = --------------------
Date 4 = -----------------
Date 5 = -----------------------
Date 6 = -----------------------
Date 7 = --------------------------
Date 8 = --------------------------
Date 9 = --------------------
Year 1 = -------
Year 2 = -------
Year 3 = -------
Power Plant = -----------------------------------
Location 1 = ----------------------
Location 2 = ----------------------------
Coal Type 1 = -----------------------------------------
Coal Type 2 = ----------
Coal Type 3 = ----------------
Mine 1 = -----------------------------
 2 PLR-103678-15

Mine 2 = -----------------------------
Mine 3 = ---------------------
Mine 4 = ---------------------
Process 1 = ------------------------
Additive 1-A = ---------------
Additive 1-B = ----------------
Process 2 = -------------------------
Additive 2-A = ---------------
Additive 2-B = ---------------
Center = ----------------------------------------------------------
a = ----
b = ----
c = ----

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 7, and ending on Date 8, with automatic renewals for four successive one-year periods, and final renewal period ending on Date 9 (Facility Lease). Company B is wholly owned by Company C. The Facility was designed and 3 PLR-103678-15

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 in Location 1. In Year 2 and Year 3, the Facility was modified to include equipment more suitable to the Process

2. All of the major components of the Facility were incorporated into the modified
   Facility.

   The Power Plant, which is owned by Company D, is a coal-fired, steam-powered
   electric generating plant in regular commercial operation. The Power Plant uses two cyclone coal-fired boilers and one pulverized coal boiler 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 is obtained from the Mine 1, the Mine 2, the Mine 3, and the Mine 4 in the Location 2. 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.

B. The Processes

The technology employed to produce the refined coal in the Facility that the Power Plant will burn in its cyclone coal-fired boilers is a proprietary process known as the Process 1, designed to reduce NOx and mercury emissions in cyclone coal-fired boilers. The rights to the Process 1 are owned by Company E. Taxpayer has sublicensed those rights from Company C for the full term of the Facility Lease.

To produce refined coal at the Facility using the Process 1, two separate inorganic chemical additives (the “Process 1 Chemical Additives”) are applied to the coal feedstock at a rate determined by a programmable logic controller. The first Process 1 Chemical Additive, referred to as Additive 1-A, is a granular iron oxide material that mixes evenly with the coal and affects the melting properties of the coal’s native ash during combustion in the power plant boilers to allow the boiler to be operated over a wider range of operating conditions resulting in a more reliable slag layer. This layer allows adjustment of the stoichiometric, or air-fuel, ratio in the boiler and provides more favorable operating conditions for reliability and reduction of NOx emissions. The second Process 1 Chemical Additive, referred to as Additive 1-B, is an inorganic solution of potassium iodide that decomposes and reacts with elemental mercury oxidizing more of it, reducing its vapor pressure under conditions typical in the particulate control device. This allows more of the mercury to be captured with the fly- ash in the particulate control equipment, resulting in a higher degree of removal.

The technology employed to produce refined coal in the Facility that the Power Plant will burn in its pulverized coal boiler is a proprietary process known as the Process 2, designed to reduce NOx and mercury emissions in pulverized coal boilers. The rights to 4 PLR-103678-15

the Process 2 are owned by Company E. Taxpayer has sublicensed those rights from Company C for the full term of the Facility Lease.

To produce refined coal at the Facility using the Process 2, two separate inorganic chemical additives (the “Process 2 Chemical Additives”) are applied to the coal feedstock at a rate determined by a programmable logic controller. The first Process 2 Chemical Additive, referred to as Additive 2-A, is a solid or liquid urea, ammonia, or amine-based material combined with a relatively pure form of an alkaline earth metal hydroxide, which reduces NOx emissions. The second Process 2 Chemical Additive, referred to as Additive 2-B, is an inorganic solution of potassium iodide which decomposes and reacts with elemental mercury in flue gas to facilities its capture in air pollution control devices.

The Facility’s equipment transports the Chemical Additives for both Processes to coal conveyor belts where they are each applied evenly to the coal feedstock. 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

1. CEMS Field Testing

Company C engaged Company E to conduct continuous emission monitoring system (CEMS) field testing of the cyclone boilers in the Power Plant from Date 1 to Date 2, and from Date 3 to Date 4. The tests were conducted using Coal Type 1 feedstock and refined coal produced in the Facility using the Process 1 from the same Coal Type 1 feedstock using the Process 1 Additives.

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

for NOx and mercury emissions, one boiler at the Power Plant was operated at or above a% of full load for a three-hour period using the coal feedstock, and NOx and mercury emissions were measured using CEMS systems. NOx emissions were measured upstream of any post-combustion NOx emissions controls. Mercury emissions were measured upstream of any scrubber or mercury control device and downstream of the electrostatic precipitator (ESP), which controls particulate emissions. The test results indicated that burning refined coal produced at the Facility using the Process 1 in the cyclone boilers resulted in a reduction in NOx emissions in excess of b% and a 5 PLR-103678-15

reduction in mercury emissions in excess of c% (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, 2010-2 C.B. 403 (the Notice), including verification that the ESP was operated under the same conditions throughout the test period.

2. Pilot Scale Emissions Testing

   Company C has not conducted CEMS field testing of the refined coal produced at
   the Facility with respect to the Process 2. Instead, from Date 5 to Date 6, Company C arranged for a series of CEMS tests to be performed at a combustion test facility (CTF) at the Center to evaluate the effectiveness of the Process 2 Chemical Additives on emissions of NOx and mercury during combustion of Coal Type 1 from the Power Plant. Company C provided the feedstock coal and the refined coal samples used for the tests. The coal used for the tests was Coal Type 1 taken from the coal stockpile at the Power Plant. The refined coal was produced using the Process 2 Additives. The CTF Report issued by the Center indicated that burning refined coal produced using the Process 2 in a pulverized coal boiler resulted in a reduction of NOx in excess of b% and a reduction of mercury emissions in excess of c% (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 pilot-scale
   test have been verified by an independent licensed professional engineer experienced in combustion and environmental engineering, as required by the Notice, including verification that the test methods used accurately measured the emissions reductions that would be achieved in a commercial boiler.

B. Redetermination Testing

Taxpayer will conduct additional emissions tests with respect to refined coal produced using both of the Processes on or before the first to occur of: (i) a change in one or both of the Processes 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 1, Taxpayer will conduct CEMS field testing or use another testing methodology permitted by section 6 PLR-103678-15

6.03 of the Notice or any subsequent applicable IRS guidance (“Determination Test”). However, if additional testing is conducted due to a change in the Process 2, Taxpayer will conduct pilot scale emissions testing at the Center or at similar pilot-scale combustion testing facilities. Taxpayer anticipates that where there has been no change in the Processes, 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 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. Redetermination testing using laboratory analysis for the Process 2 will use samples of feedstock coal and refined coal collected at the CTF at the Center during the pilot-scale testing from the feedstock coal and refined coal used to conduct the Determination tests.

C. Additive Rate Tests

Parent retained Company F, 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 F reviewed the results of CEMS emissions testing conducted at five different power plants using refined coal produced from Coal Type 1, Coal Type 2, and blends of Coal Type 1 and Coal Type 3. 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 F’s review of those test results, it 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 Processes 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.
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PLR-103678-15

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 modification of the Facility in Year 2 and Year 3,
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.

5) Testing by the Center or another qualified pilot-scale combustion facility for
qualified emissions reductions as described in the CTF Report satisfies the
requirements of Notice 2010-54. Taxpayer may rely on the pilot scale testing
conducted at the Center to satisfy the qualified emission reduction test of
§ 45(c)(7)(B).

6) 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 8 PLR-103678-15

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.

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 process 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 9 PLR-103678-15

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).

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 10 PLR-103678-15

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 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 Processes involve blending feedstock coal with the Chemical Additives in two cyclone coal-fired boilers and one pulverized coal boiler. Section 6.01 of the Notice provides generally that a qualified 11 PLR-103678-15

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 provided 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 Processes are not mining processes. 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 that 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 Processes 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 § 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 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 12 PLR-103678-15

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), the subsequent modification of the Facility in Year 2 and Year 3, 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, 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 NOx, SO2 or mercury, provided the method used for any pollutant is a permissible method. Section 6.04(1) of the Notice provides that an emission test establishing a “qualified emission reduction” qualifies the refined coal for a six-month period provided there is no change in the process for producing the refined coal or in the source or rank of the feedstock coal. Therefore, a taxpayer must “redetermine” the emission reductions to qualify for the succeeding six-month period using one or more approved methods. In the instant case, pilot-scale combustion testing will be arranged for the redetermination of the emissions reductions using the Process 2, which is permitted under section 6.03 of the Notice. Specifically, Taxpayer will arrange to have the Center conduct testing (including redetermination testing) at the CTF or at similar pilot-scale combustion testing facility to determine the emissions reductions associated with burning the refined coal product compared to the feedstock coal. For purposes of qualifying the refined coal produced at the Facility, the Center has conducted pilot-scale combustion tests at the CTF as documented in the CTF Report. In conducting such tests, the Center conducted tests on the coal feedstock, and then mixed a separate sample of the coal feedstock with the Process 2 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 the feedstock coal and the 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 CTF reports (including interim reports) satisfies the requirements of the Notice. Taxpayer may rely on the pilot scale testing at the Center to satisfy the qualified emission reduction test of § 45(c)(7)(B).

With respect to the sixth 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 that the redetermination requirement of section 6.04 may be satisfied by laboratory analysis 13 PLR-103678-15

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 testing or other test that meet the requirements of section 6.03.

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)