PLR 201220021: Refined coal process qualifies for section 45 treatment

Plain-English summary

The IRS approved a refined-coal production process that mixes proprietary additives with feedstock coal before combustion. The ruling concludes that the process can produce refined coal for purposes of the section 45 credit if the feedstock and emissions meet the stated requirements. It also approves the taxpayer’s use of pilot-scale combustion testing and later laboratory analysis to establish or redetermine the required reductions in nitrogen oxide and sulfur dioxide or mercury emissions. The ruling is limited to the stated facts and does not decide who produced the coal, whether it was sold to an unrelated person, or when the facility was placed in service.

Ruling snapshot

• Question: Does the taxpayer’s additive-based process, testing program, and feedstock controls satisfy the requirements for section 45 refined-coal treatment?
• Outcome: Approved
• Key authorities: IRC §§ 45 and 613; Notice 2010-54, sections 3.01, 3.03, 3.04, 6.01, 6.03, 6.04, and 6.05

Full text (IRS public release)

Internal Revenue Service
Department of the Treasury
Washington, DC 20224

Number: 201220021
Third Party Communication: None
Release Date: 5/18/2012
Date of Communication: Not Applicable
Person To Contact:
Index Number: 45.00-00
-----------------------, ID No. -------------
Telephone Number:
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Refer Reply To:
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CC:PSI:B6
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PLR-149063-11
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Date:
February 08, 2012

LEGEND:
Partnership = ---------------------------------------
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Taxpayer = --------------------------------
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Parent = ----------------------------------------
Business A = --------------------------------------------------
Corp A = ---------------------------------
Corp B = -----------------------------------
Corp C = ----------------------------------------
Corp D = -------------------------------
Corp E = ---------------------------------
Corp F = --------------------------------
Corp G = ----------------------
State A = -------------
State B = ------------
Plant = ---------------------------
a = --
b = --------
c = --
d = ----
e = ----
f = ----
g = ----
Additive 1 = ---------------------
Additive 2 = ------------------------------------
Test Rep 1 = ------------------------------------------------------------------------------------------
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Test Rep 2 = ------------------------------------------------------------------------------------------
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Test Rep 3 = ------------------------------------------------------------------------------------------
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Test Rep 4 = ------------------------------------------------------------------------------------------
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Center = ------------------------------------------------------------------------------------------
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Date 1 = --------------------------
Date 2 = --------------------------
Date 3 = -----------------------
Date 4 = --------------------
Date 5 = --------------
Date 6 = -----------------
Source Region A = --------------------------
Source Region B = ----------------------------

Dear --------------------

This is in response to your request for rulings, submitted by your authorized representative, concerning the federal income tax consequences of the transaction described below:

Background

Partnership, a State A limited liability company, is a calendar year taxpayer and employs the accrual method of accounting for both book and tax purposes.

Taxpayer is a State A corporation and wholly owned, indirect subsidiary of Parent, a publicly traded State A corporation that is primarily engaged, through its ownership of interest in subsidiaries and other companies, in Business A.

The members of Partnership are Taxpayer and Corp A, a State A limited liability company. Corp A is a wholly-owned subsidiary of Corp B and has elected to be taxable as a corporation for federal tax purposes. Corp B is wholly owned by Corp C, which is wholly owned by Corp D. Corp B is engaged in the business of developing and managing various energy-related projects throughout the United States, including backup power generation projects, power-house operations, cogeneration facilities, coke batteries, and similar energy-related projects. Corp D is the holding company for a number of operating companies engaged in energy-related businesses. Corp D is also the parent company of Corp E, the regulated public electric utility for a portion of State B. Other subsidiaries of Corp D sell coal and coal transportation services throughout the United States. Corp D and its affiliates are calendar year taxpayers and employ the accrual method of accounting for book and tax purposes.

On Date 1, Taxpayer purchased 100% of the Class B membership interests in Partnership from Corp A in a transaction treated as a taxable sale of a proportionate 3 PLR-149063-11

share of all of Partnership’s assets from Corp A to Taxpayer, followed by a contribution of Partnership’s assets by both Taxpayer and Corp A to a newly formed partnership.

Partnership constructed a facility consisting of two parallel, independent production lines that are designed to produce refined coal. The two production lines presently are located at Plant. Corp E owns Plant. As originally designed and constructed, each of the two production lines is capable of being operated as a separate unit to produce refined coal. Plant is comprised of a coal-fired generating units with an electric generating capacity of approximately b megawatts in the aggregate. Plant consumes approximately c million tons of coal per year.

Prior to the transaction with Taxpayer described above, Partnership sold production line #2 to Corp F, which is wholly owned by Corp B. Partnership retained ownership of production line #1, which it now operates to produce refined coal that is sold to Corp E. In addition, Corp F leased production line #2 back to Partnership on a month-to-month basis ending no later than Date 2, and Partnership presently operates production line #2 to produce refined coal that also is sold to Corp E. All of the refined coal is used as a fuel at Plant to produce steam for the generation of electricity.

Description of the Process

The process at issue for production of refined coal currently employed at the facility involves the mixing of proprietary chemicals (additives) with feedstock coal prior to combustion (the Process). The patent for the Process is owned by Corp G and is licensed to Partnership. Corp G is entitled to certain per ton royalties based on production for the use of its technology. Test results have shown that when mixed with coal, the proprietary additives result in reduced NOx, SO2 and mercury emissions during combustion. Different chemicals are targeted at specific pollutants. Based on the characteristics of the feedstock coal burned at the Plant, Partnership has chosen a combination of additives that target the reduction of NOx and mercury. In the case of NOx, Partnership understands that Additive 1 is believed to cause a portion of the NOx to adhere to, or react with, the additive so that it can be captured and is not emitted. In the case of mercury, Partnership understands that Additive 2 is believed to react with the elemental mercury in the feedstock coal so that it is converted into a chemical species of mercury (mercury oxide) that can be effectively captured by particulate control devices. A by-product of the Process is a valuable fly ash that can be used in a diverse array of applications in the steel, mining and cement industries.

Emissions Reduction Testing

For purposes of determining emissions reductions under § 45 of the Internal Revenue Code, Partnership will arrange for pilot-scale combustion testing (and laboratory analysis for redetermination purposes), and will not rely on any continuous emissions monitoring system or other field testing. Corp B engaged the research center of a prominent university (the Center) to conduct tests on behalf of the Partnership at its 4 PLR-149063-11

pilot-scale combustion test facility (CTF) to determine the emission reductions associated with burning the refined coal compared to the feedstock coal. Center reports described below state:

The CTF has been extensively used to research and investigate SOx and NOx emissions and the transformation of toxic trace metals (Hg [mercury], As, and Pb) during the combustion of coal and other fuels or waste materials. The CTF is capable of producing gas and particulate samples that are representative of those produced in industrial- and full-scale pulverized coal (pc)-fired boilers.

For purposes of qualifying the refined coal produced at the facility, Center conducted pilot-scale combustion tests at its CTF on Date 4 on three blends of feedstock coal of the type typically burned at the Plant. Subsequently, on Date 5 Center conducted a separate test on one blend of feedstock coals typically burned at the Plant, and on Date 6 Center conducted another test on a single type of feedstock coal, which is a component of the blends of feedstock coal typically burned at the Plant.

The Center reports explain that combustion gas analysis is provided by continuous emissions monitors (CEMs) at two locations: the furnace exit, which is used to monitor and maintain a specified excess air level for all test periods, and the outlet of the particulate control device, which is used to assess any air inleakage that may have occurred so that emissions of interest sampled at the back end of the system can be corrected for the dilution caused by the inleakage. Flue gas analyses were obtained from the duct at the outlet of the electrostatic precipitator (ESP). Flue gas mercury measurements were obtained separately by a continuous mercury monitor located at the flue gas ducting at the exit of the particulate control device. Center conducted a series of tests on the feedstock and refined coal blends, measuring the emissions with these devices.

Test Rep 1 states that the test results indicate that the blend of coal and additives achieved the required reductions in both NOx and total mercury emissions (both determined on a lb/Btu basis) to satisfy the requirements of at least 20% NOx reduction and at least 40% mercury reduction. Test Rep 1 states that it is expected the emissions reduction reported would be achieved at full scale using the additive levels tested. Similar conclusions are reached by Center in Test Rep 2 and Test Rep 3.

Separately, in Test Rep 4, Center concluded that refined coal production using d% to e% coal from Source Region A and f% to g% coal from Source Region B can be expected to meet the emission reduction requirements outlined in § 45.

Tested Coal

Plant currently burns a blend of subbituminous coal from a number of mines in Source Region A and bituminous coal from a number of mines in Source Region B. 5 PLR-149063-11

Partnership produces refined coal using a blend of coals from both source regions and sells that refined coal to Plant which burns it to generate electricity from steam.

The rank of the Source Region A coal burned at the Plant is classified by the American Society of Testing Materials (ASTM) as subbituminous coal with a gross calorific value of 8,300 to 9,500 btu/lb, and the rank of the Source Region B coal burned at the Plant is classified as high volatile bituminous coal with a gross calorific value of 11,500 to 14,000 btu/lb. The source Region B coal used by Partnerhsip is washed at a coal preparation plant to meet the Plant’s specifications. The coal blend used by Partnership as feedstock for the Process contains d% to e% Source Region A coal and f% to g% Source Region B coal. Variations in the coal blend result from the supply and availability of the coals and the needs of the Plant.

Partnership requested that Center test blends of the source region A and source region B coals that represent the range of coal blends to be used to produce refined coal that will be burned to produce steam at the Plant. As described above, the coal blend burned at the Plant contains d% to e% Source Region A coal and f% to g% Source Region B coal. Accordingly, Center tested the range of coal blends in its reports described above. For purposes of this letter, the term “Tested Coal” refers to coal or a blend of coals comprising d% to e% Source Region A coal and f% to g% Source Region B coal.

Center reports that based on test results over the past year, refined coal produced from all Tested Coal is expected to meet the emission reduction requirements outlined in § 45 of the Code when compared with the feedstock coal.

Partnership expects to continue to operate with the blends and additive levels discussed in the Center reports, which would be consistent with long-term patterns for coal consumed at the Plant. If so, samples will be taken for redetermination testing within six months after the last emissions test satisfying the qualified emission reduction requirement. Thereafter, within six months after such date, another set of samples will be taken for redetermination testing. In each case, samples will be collected and prepared in accordance with sampling and testing procedures set forth in the Partnership’s operating protocols.

Although Partnership does not currently anticipate making changes to its coal feedstock or additive levels, or using other coal sources or ranks, additional testing will be conducted prior to acquiring coal feedstock from a different coal source region or of a different rank than reflected in the Tested Coal. In the case of a change in the additive levels, tests will also be run at the new minimum levels of additive as the qualified expert advises is necessary to conclude that a qualified emissions reduction will be expected for the new levels of additive.

In addition, Partnership may collect and test composite samples of feedstock and refined coal to determine the average sulfur and mercury content of the samples. As 6 PLR-149063-11

such samples are collected, a rolling six-month average of the laboratory analyses would be computed to determine whether there has been a change of the sulfur or mercury content by more than ten percent.

RULINGS REQUESTED

Based on the foregoing, you have requested that we rule as follows:

1. The refined coal produced by using the Process constitutes “refined coal” within the meaning of §45(c)(7) of the Code, provided that such refined coal is produced from feedstock coal that is the same source or rank as the “Tested Coal” and provided further that the refined coal satisfies the qualified emission reduction test stated in §45(c)(7)(B).

2. Provided that the feedstock coals used to produce refined coal during any determination period are from the same coal source regions and of the same rank as the Tested Coal, all feedstock coal that satisfies that criteria shall be treated as feedstock coal of the same source and rank for purposes of section 6.04 of Notice 2010-54, 2010-40 I.R.B 403, regardless of the mine from which such feedstock coal is purchased.

3. Testing by Center for qualified emissions reduction as set forth in its test reports satisfies the requirements of Notice 2010-54. Taxpayer may rely on the pilot scale testing conducted at Center (and subsequent permitted laboratory testing as required for a redetermination described in section 6.04(2)(a) or (b) of Notice 2010-54) to satisfy the qualified emission reduction test of §45(c)(7)(B) of the Code regardless of subsequent normal fluctuations in operating conditions and emissions at the Plant.

4. Pursuant to section 6.04(2)(b) of Notice 2010-54, the redetermination requirement of section 6.04 of Notice 2010-54 may be satisfied by laboratory analysis establishing that the sulfur and mercury content of both the feedstock coal and the refined coal, on average, do not vary by more than ten percent from the sulfur and mercury content of the feedstock coal and the refined coal used in the most recent determination that meets the requirements of section 6.03 of Notice 2010-54.

LAW AND RATIONALE

Section 45(a) of the Code generally provides a credit against federal income tax for the use of renewable or alternative resources to produce electricity or fuel for the generation of steam. Section 45(e)(8) of the Code provides that, in the case of a producer of “refined coal”, the credit available under §45(a) of the Code for any taxable year shall be increased by an amount equal to $4.375 per ton of qualified “refined coal” (i) produced by the taxpayer at a “refined coal production facility” during the 10-year period beginning on the date that the facility was originally placed in service, and which 7 PLR-149063-11

is (ii) sold by the taxpayer to an unrelated person during such 10-year period and such taxable year.

For purposes of §45 of the Code, section 3.01 of Notice 2010-54 provides that the term “refined coal” means a fuel which – (i) is a liquid, gaseous, or solid fuel (including feedstock coal mixed with an additive or additives) produced from coal (including lignite) or high carbon fly ash, including such fuel used as a feedstock, (ii) is sold by the taxpayer with the reasonable expectation that it will be used for the purpose of producing steam, and (iii) is certified by the taxpayer as resulting (when used in the production of steam) in a qualified emission reduction. Section 3.04 of the Notice provides that the term “qualified emission reduction” means, in the case of refined coal produced at a facility placed in service after December 31, 2008, a reduction of at least twenty percent (20%) of the emissions of nitrogen oxide and at least forty percent (40%) of the emissions of either sulfur dioxide or mercury released when burning the refined coal (excluding any dilution caused by materials combined or added during the production process), as compared to the emissions released when burning the feedstock coal or comparable coal predominantly available in the marketplace as of January 1, 2003.

Section 45(d)(8) of the Code generally provides that the term “refined coal production facility” means a facility which is placed in service after October 22, 2004 and before January 1, 2012.

Section 6.01 of Notice 2010-54 generally provides that a qualified emissions reduction does not include any reduction attributable to mining processes or processes that would be treated as mining (as defined in §613(c)(2), (3), (4)(A), (4)(C), or (4)(I)) if performed by the mine owner or operator. Accordingly, in determining whether a qualified emission reduction has been achieve, the emissions released when burning the refined coal must be compared to the emissions that would be released when burning the feedstock coal. Feedstock coal is the product resulting from processes that are treated as mining and are actually applied by a taxpayer in any part of the taxpayer’s process of producing refined coal from coal.

Section 613(c)(5) of the Code describes treatment processes that are not considered as mining unless they are provided for in §613(c)(4) or are necessary or incidental to a process provided for in §613(c)(4). Any cleaning process, such as a process that uses ash separation, dewatering, scrubbing through a centrifugal pump, spiral concentration, gravity concentration, flotation, application of liquid hydrocarbons or alcohol to the surface of the fuel particles or to the feed slurry provided such cleaning does not change the physical or chemical structure of the coal, and drying to remove free water, provided such drying does not change the physical or chemical identity of the coal, will be considered as mining.

Section 6.03(1) of the Notice provides, in part, that emissions reduction may be determined using continuous emission monitoring system (CEMS) field testing. Section 8 PLR-149063-11

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

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

Section 6.04(1) of the Notice provides that a taxpayer may establish that a qualified emission reduction determined under section 6.03 applies to production from a facility by a determination or redetermination that is valid at the time the production occurs. A determination or redetermination is valid for the period beginning on the date of the determination or redetermination and ending with the occurrence of the earliest of the following events: (i) the lapse of six months from the date of such determination or redetermination; (ii) a change in the source or rank of the feedstock coal that occurs after the date of such determination or redetermination; or (iii) a change in the process of producing refined coal from the feedstock coal that occurs after the date of such determination or redetermination.

Section 6.04(2) of the Notice provides that in the case of a redetermination required because of a change in the process of producing refined coal from the feedstock coal, the redetermination required under section 6.04 must use a method that meets the requirements of section 6.03. In any other case, the redetermination requirement may be satisfied by laboratory analysis establishing that – (a) the sulfur (S) or mercury content of the amount of refined coal necessary to produce an amount of useful energy has been reduced by at least 20 percent (40 percent, in the case of facilities placed in service after December 31, 2008) in comparison to the S or mercury content of the amount of feedstock coal necessary to produce the same amount of useful energy, excluding any dilution caused by materials combined or added during the production process; (b) the S or mercury content of both the feedstock coal and the refined coal do not vary by more than 10 percent from the S and mercury content of the 9 PLR-149063-11

feedstock coal and refined coal used in the most recent determination that meets the requirements of the Notice.

Finally, section 6.05 of the Notice provides that the certification requirement of section 3.01(1)(c) of the Notice is satisfied with respect to fuel for which the refined coal credit is claimed only if the taxpayer attaches to its tax return on which the credit is claimed a certification that contains the following: (1) a statement that the fuel will result in a qualified emissions reduction when used in the production of steam; (2) a statement indicating whether CEMS field testing was used to determine the emissions reduction; (3) if CEMS field testing was not used to determine the emissions reduction, a description of the method used; (4) a statement that the emissions reduction was determined or redetermined within the six months preceding the production of the fuel and that there have been no changes in the source or rank of the feedstock coal used in the process of producing refined coal from feedstock coal since the emissions reduction was most recently determined or redetermined; and (5) a declaration signed by the 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.”

With respect to the first issue, the Process starts with several chemical additives being added to the feedstock coal prior to its combustion in a furnace. The additives provide the chemical structure that results in the reduction of emissions of nitrogen oxide and mercury during combustion. Section 6.01 of the Notice provides generally that a qualified emissions reduction does not include any reduction attributable to mining processes or processes that would be treated as mining if performed by the mine owner or operator. In the instant case, the Process is not a mining process. Further, section 3.01 of the Notice clarifies §45(c)(7) of the Code and specifically provides that refined coal includes feedstock coal mixed with additives. Thus, additive processes that mix certain chemicals or other additives with the coal in order to achieve emissions reductions may qualify for the refined coal production tax credit. Additionally, section 3.03 defines comparable coal as coal that is of the same rank as the feedstock coal and that has an emissions profile comparable to the emissions profile of the feedstock coal. Accordingly, we conclude that the coal produced by using the Process constitutes a “refined coal” within the meaning of §45(c)(7) of the Code, provided that the refined coal (i) is produced from feedstock coal that is the same source or rank as the “Tested Coal” and (ii) satisfies the qualified emission reduction test stated in §45(c)(7)(B) of the Code.

With respect to the second issue, the emissions profile of the refined coal product is compared to the emissions profile of either the feedstock coal or a comparable coal predominantly available in the marketplace as of January 1, 2003. Section 3.03 of the Notice provides that a “comparable coal” is defined as coal that is of the same rank as the feedstock coal and that has an emissions profile comparable to the emissions profile of the feedstock coal. Section 6.04 of provides that a determination or redetermination of a qualified emissions reduction is valid until the occurrence of the earliest of the 10 PLR-149063-11

following events: (i) the lapse of six months from the date of such determination or redetermination; (ii) a change in the source or rank of the feedstock coal that occurs after the date of such determination or redetermination; or (iii) a change in the process of producing refined coal from the feedstock coal that occurs after the date of such determination or redetermination. Accordingly, we conclude that provided that the feedstock coals during any determination period are from the same coal source regions and of the same rank as the Tested Coal, all feedstock coal that satisfies that criteria shall be treated as feedstock coal of the same source and rank for purposes of section 6.04 of Notice 2010-54, regardless of the mine from which such feedstock coal is purchased.

With respect to the third issue, section 6.03(3) of the Notice provides that any permissible testing method provided for in the Notice can be used in emission testing for any pollutant. That is, a taxpayer can use different testing methods for each of nitrogen oxide, sulfur dioxide or mercury, provided the method used for any pollutant is a permissible method. Section 6.04(1) provides that an emission test establishing a “qualified emission reduction” qualifies the refined coal for a six-month period provided there is no change in the process for producing the refined coal or in the source or rank of the feedstock coal. Therefore, a taxpayer must “redetermine” the emission reductions to qualify for the succeeding six-month period using one or more approved methods. In the instant case, Partnership will arrange for pilot-scale combustion testing, and will not rely on any continuous emissions monitoring system or other field testing, which is permitted under section 6.03 of the Notice. Specifically, Partnership will arrange with the Center to conduct testing (including redetermination testing) at its CTF to determine the emissions reductions associated with burning the refined coal product compared to the feedstock. For purposes of qualifying the refined coal produced at the facilities, the Center has conducted pilot-scale combustion tests at its CTF as documented in Test Rep 1, Test Rep 2, Test Rep 3, and Test Rep 4. In conducting such tests, the Center conducted tests on the feedstock, and then mixed a separate sample of the feedstock with the additives so that it could conduct tests on the refined coal product. In each of its reports, the Center reported that the test results indicated that the blend of coal and additives achieved the required emissions reductions. Based on the foregoing, we conclude that testing by the Center for qualified emissions reductions as set forth in its test reports (including interim reports) satisfies the requirements of Notice 2010-54. Partnership may establish a qualified emissions reduction through testing by the Center at its combustion research facility or similar pilot-scale combustion testing facilities under Notice 2010-54, regardless of subsequent normal fluctuations in operating conditions and emissions at the power plants where the refined coal is burned.

With respect to the fourth issue, 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 11 PLR-149063-11

other case, the redetermination requirement may be satisfied by laboratory analysis establishing that the sulfur and mercury content of both the feedstock coal and the refined coal do not vary by more than 10 percent from the sulfur and mercury content of the feedstock coal and refined coal used in the most recent redetermination that meets the requirements of the Notice. Accordingly, we conclude that the redetermination requirement of section 6.04 of Notice 2010-54, may be satisfied by laboratory analysis establishing that the sulfur and mercury content of both the feedstock coal and the refined coal, on average, do not vary by more than 10 percent from the sulfur and mercury content of the feedstock coal and refined coal used in the most recent determination that meets the requirements of section 6.03 of Notice 2010-54.

No opinion is expressed regarding any other issue not specifically addressed in this ruling letter. In particular, no opinion is expressed with respect to (1) whether Taxpayer or any of its affiliates is the Producer of the refined coal for purposes of § 45(e)(8) of the Code; (2) whether there has been a sale of refined coal to an unrelated person; or (3) when the Facility was, in fact, placed in service.

In accordance with the Power of Attorney on file with this office, we are sending a copy of this letter to your authorized representatives. A copy of this ruling must be attached to any income tax return to which it is relevant. Alternatively, taxpayers filing their returns electronically may satisfy this requirement by attaching a statement to their return that provides the date and control number of the letter ruling.

This ruling is directed only to the Taxpayer who requested it. Section 6110(k)(3) of the Code provides it may not be used or cited as precedent. We are sending a copy of this letter ruling to the Industry Director.

Sincerely,

Peter C. Friedman
Senior Technician Reviewer, Branch 6
Office of Associate Chief Counsel (Passthroughs & Special Industries)

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