Electricity Produced from Certain Renewable Sources

Internal Revenue Service
Number: 201519024
Release Date: 5/8/2015
Index Number: 45.00-00
---
---
---
---
LEGEND
Taxpayer = ---
---
Company A = ---
Company B = ---
Company C = ---
Department of the Treasury
Washington, DC 20224
[Third Party Communication:
Date of Communication: Month DD, YYYY]
Person To Contact:
---, ID No. ---
Telephone Number:
---
Refer Reply To:
CC:PSI:B06
PLR-139362-14
Date: January 29, 2015
---
Company D =
---
Company E =
Company F = ---
Company G = ---
---
Company H =
Parent = ---
---
Business A =
Business B = ---
---
Utility =
---
Supplier =
Operator = ---
Licensor = ---
State A = ---
State B = ---
State C = ---
State D = ---
State E = ---
Plant A = ---
Plant B = ---
---
Plant C =
Date 1 = ---
Date 2 = ---
Date 3 = ---
PLR-139362-14 2
Date 4 = ---
Date 5 = ---
Date 6 = ---
Date 7 = ---
Date 8 = ---
Date 9 = ---
Date 10 = ---
Date 11 = ---
Additive 1 = ---
Additive 2 = ---
Center = ---
---
Test Rep 1 = ---
---
Test Rep 2 = ---
---
Test Rep 3 = ---
--- source region A = ---
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. The facts, as represented, are as follows:

# Background

Company H, a State A limited liability company, is a calendar year taxpayer and employs the accrual method of accounting for both book and tax purposes. Company H owns all of the interests in Company A, Company B and Company C, each of which is a State A limited liability company. The members of Company H are Company D and Investor, each of which is a State A limited liability company.
Company D is owned by Company E, a State B limited liability company, and Company F, a State C limited liability company. Each of Company D, Company E and Company F is an affiliate of Company G, a State C corporation that is primarily engaged in Business A.
Taxpayer is a State A limited liability company that is an indirect, wholly owned subsidiary of Parent, a State A corporation that is primarily engaged in Business B.
PLR-139362-14 3
Taxpayer has elected to be classified as an association taxable as a corporation for U.S. federal tax purposes.
Company H was organized on Date 1 to hold the interests in Company A, Company B and Company C. Prior to Date 2, all of the interests in Company H were held by Company D. On Date 3, Company D transferred three facilities for the production of refined coal to each of Company A, Company B and Company C. Each of those facilities was constructed and placed in service at a site in State B on or about Date 4 and produced and sold refined coal with the expectation that it would be burned to produce steam. Company D continued to operate the facilities at that location until Date 5.
On Date 6, Company A entered into contracts with Utility to locate a refined coal production facility on a site adjacent to Plant A in State D, and to sell refined coal produced in that facility to Utility. Also on Date 6, Company A entered into an agreement with Supplier, an affiliate of Utility, to purchase coal feedstock to be used in its refined coal production facility. Separately, on Date 7, Company B entered into similar agreements with Utility to locate a refined coal production facility on a site adjacent to Plant B in State D and to purchase coal feedstock for that facility from Supplier. Likewise, on Date 8 Company C entered into similar agreements with Utility to locate a refined coal production facility on a site adjacent to Plant C in State D and to purchase coal feedstock from that facility from Supplier. Subsequently, each of Company A, Company B and Company C relocated their respective facilities to those sites, where they now are in operation.
On Date 2, Taxpayer acquired all of the class B membership interests in Company H from Company D in a transaction treated as a taxable sale or exchange of an undivided interest in the assets of Company H, followed by a contribution of Company H’s assets by both Taxpayer and Company D to a newly formed partnership.
Simultaneously, Taxpayer and Company D entered into a limited liability agreement with respect to Company H, setting forth their agreement regarding the respective rights and obligations of the class A and class B interests in Company H, the management and related decision-making of Company H, and certain related matters.
Pursuant to the agreements with Supplier, each of Company A, Company B and Company C purchases coal feedstock from Supplier. Some of that coal feedstock was purchased at the sites where the facilities are located, and some of the coal feedstock is purchased when loaded on barges or railcars that subsequently deliver the coal to such sites. The coal supply agreements do not prohibit the companies from purchasing coal feedstock from third parties, and do not prohibit them from purchasing more feedstock coal than Utility would expect to buy from them in the form of refined coal.
The feedstock coal purchased by each of Company A, Company B and
Company C typically is coal that Supplier itself purchased from third party vendors, consistent with coal specifications provided by Utility. The companies use the Process PLR-139362-14 4 (as described below) to produce refined coal that they sell to Utility pursuant to refined coal sales agreements. All of the refined coal produced in their facilities is expected to be used as a fuel at Utility’s power plants to produce steam for the generation of electricity. However, any refined coal not purchased by Utility can be sold to one or more third parties.
None of the Company H, Company A , Company B and Company C have any employees. Rather, each of Company A, Company B and Company C entered into separate operations and maintenance agreements with Operator, a State A limited liability company and affiliate of Company D. Pursuant to those agreements, Operator will operate, repair and maintain the facilities in accordance with an agreed operating plan, will make arrangements to coordinate delivery of spare parts and supplies, will coordinate deliveries of coal feedstock purchases and sales of refined coal, and will perform certain administrative functions in support thereof. In addition, Operator will arrange for testing of refined coal as described below.
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 licensed by Licensor to each of Company A, Company B and Company C. Licensor is entitled to certain per ton royalties based on production for the use of the 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 plants, the companies have chosen a combination of additives that target the reduction of NOx and mercury. In the case of NOx, the companies understand 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, the companies understand 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.
Emissions Reduction Testing
For purposes of determining emissions reductions under § 45, each of Company A, Company B and Company C 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. The companies engaged the research center of a prominent university (the Center) to conduct tests at its pilot-scale combustion test facility (CTF) to determine the emission reductions associated with burning the refined coal compared to the feedstock coal. Center reports described below state:
PLR-139362-14 5
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.
The CTF is capable of producing gas and particulate samples that are representative of those produced in industrial and full-scale pulverized coal boilers, and has several pollution control devices that may be used to reduce emissions, including an electrostatic precipitator or fabric filter baghouse for particulate control, a selective catalytic reduction column for NOx control, and a wet scrubber for control of sulfur emissions. For purposes of qualifying the refined coal produced at the facilities, Center conducted pilot-scale combustion tests at its CTF on Dates 9, 10 and 11 on feedstock coal of the type typically burned at Plant A, Plant B and Plant C, respectively. Center issued reports with respect to each of those tests, which are referred to as Test Rep 1, Test Rep 2 and Test Rep 3 (collectively, the “Test Reports”).
Each Test Report explains that combustion gas analysis is provided by continuous emissions monitors (CEMs) at two locations: the furnace exit, which is used to monitor and maintain a specified excess air level for all test periods, and the outlet of the particulate control device, which is used to assess any air inleakage that may have occurred so that emissions of interest sampled at the back end of the system can be corrected for the dilution caused by the inleakage. Flue gas analyses were obtained from the duct at the outlet of the electrostatic precipitator. Flue gas mercury measurements were obtained separately by a continuous mercury monitor located at the flue gas ducting at the exit of the electrostatic precipitator. Center conducted a series of tests on the feedstock and refined coal blend, measuring the emissions with these devices.
Each Test Report states that the test results indicate that the blend of coal and additives achieved the required reductions in both NOx and total mercury emissions (both determined on a lb/Btu basis) to satisfy the requirements of at least 20% NOx reduction and at least 40% mercury reduction. Each Test Report also states that it is expected the emissions reduction reported would be achieved at full scale using the additive levels tested.
Tested Coal
The plants currently burn subbituminous coal obtained from various mines located in State E, within source region A. Each of Company A, Company B and Company C produce refined coal using this coal and sell that refined coal to Utility which burns it in the plants to generate electricity from steam.
PLR-139362-14 6
Company H requested that Center test a blend of coal that represents the coal to be used at the plants (the “Tested Coal”). The reports issued by Center state that the emission reduction requirements outlined in § 45 for NOx and mercury were satisfied when comparing the results of burning the endpoint fuel to the results of burning the feedstock coal.
Company H expects to continue to operate with the blend and additive levels discussed in the Center reports, which would be consistent with long-term patterns for coal consumed at the Plant. To that end, 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 Company H’s operating protocols. Although testing and preliminary reporting is done timely, the Center often is not able to issue the final report until after the six-month period.
Although Taxpayer does not currently anticipate making changes to its coal feedstock or additive levels, or using other coal sources or ranks, additional testing will be conducted prior to acquiring coal feedstock from a different coal source region or of a different rank than reflected in the Tested Coal. In the case of a change in the additive levels, tests will also be run at the new minimum levels of additive as the qualified expert advises is necessary to conclude that a qualified emissions reduction will be expected for the new levels of additive.
RULINGS REQUESTED
Based on the foregoing, you have requested that we rule as follows:
1. The refined coal produced by using the Process constitutes “refined coal” within the meaning of §45(c)(7) of the Code, provided that such refined coal is produced from feedstock coal that is the same source or rank as the “Tested Coal” and provided further that the refined coal satisfies the qualified emission reduction test stated in §45(c)(7)(B) of the Code.
2. Provided that the feedstock coals used to produce refined coal during any determination period are from the same coal source regions and of the same ranks as the Tested Coal, all feedstock coal that satisfies that criteria shall be treated as feedstock coal of the same source and rank for purposes of section 6.04 of Notice 2010-54, regardless of the mines from which such feedstock coal is purchased.
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 PLR-139362-14 7 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.
4. Pursuant to section 6.04(2)(b) of Notice 2010-54, Taxpayer may satisfy the redetermination requirement of section 6.04 of Notice 2010-54 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 below the bottom of (nor more than ten percent above the top of) the range of sulfur content and the range of mercury content of the feedstock coal and the refined coal used in the most recent determination that meets the requirements of section 6.03 of Notice 2010-54.
5. The results set forth by the Center in a redetermination test report for production may be relied upon after the date of the testing even if the report is not received until after the six month period specified in section 6.04(1)(i) of Notice 2010-54.
6. Provided a facility was “placed in service” prior to January 1, 2012, within the meaning of §45(d)(8), relocation of a facility to a different location after December 31, 2011, or replacement of part of a facility after that date, will not result in a new placed in service date for the facility for purposes of §45 provided the fair market value of the used property is more than twenty percent of the facility’s total value (the cost of the new property plus the value of the used property) at the time of relocation or replacement.
7. Provided a facility was “placed in service” prior to January 1, 2012, within the meaning of §45(d)(8), a change in ownership of a facility after December 31, 2011 will not result in a new placed in service date for the facility for purposes of §45.
LAW AND RATIONALE
Section 45(a) of the Code generally provides a credit against federal income tax for the use of renewable or alternative resources to produce electricity or fuel for the generation of steam. Section 45(e)(8) of the Code provides that, in the case of a producer of “refined coal”, the credit available under §45(a) of the Code for any taxable year shall be increased by an amount equal to $4.375 per ton of qualified “refined coal”

(i) produced by the taxpayer at a “refined coal production facility” during the 10-year period beginning on the date that the facility was originally placed in service, and which is (ii) sold by the taxpayer to an unrelated person during such 10-year period and such taxable year.
For purposes of §45 of the Code, section 3.01 of Notice 2010-54 provides that the term “refined coal” means a fuel which – (i) is a liquid, gaseous, or solid fuel (including feedstock coal mixed with an additive or additives) produced from coal (including lignite) or high carbon fly ash, including such fuel used as a feedstock, (ii) is sold by the taxpayer with the reasonable expectation that it will be used for the purpose of producing steam, and (iii) is certified by the taxpayer as resulting (when used in the PLR-139362-14 8 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 achieved, the emissions released when burning the refined coal must be compared to the emissions that would be released when burning the feedstock coal. Feedstock coal is the product resulting from processes that are treated as mining and are actually applied by a taxpayer in any part of the taxpayer’s process of producing refined coal from coal.
Section 613(c)(5) of the Code describes treatment processes that are not considered as mining unless they are provided for in §613(c)(4) or are necessary or incidental to a process provided for in §613(c)(4). Any cleaning process, such as a process that uses ash separation, dewatering, scrubbing through a centrifugal pump, spiral concentration, gravity concentration, flotation, application of liquid hydrocarbons or alcohol to the surface of the fuel particles or to the feed slurry provided such cleaning does not change the physical or chemical structure of the coal, and drying to remove free water, provided such drying does not change the physical or chemical identity of the coal, will be considered as mining.
Section 6.03(1) of the Notice provides, in part, that emissions reduction may be determined using continuous emission monitoring system (CEMS) field testing. Section 6.03(a)(1) provides, in part, that CEMS field testing is testing that meets all the following requirements: (i) the boiler used to conduct the test is coal-fired and steam-producing and is of a size and type commonly used in commercial operations; (ii) emissions are measured using a CEMS; (iii) if EPA has promulgated a performance standard that applies at the time of the test to the pollutant emission being measured, the CEMS must conform to that standard; (iv) emissions for both the feedstock coal and the refined coal are measured at the same operating conditions and over a period of at least 3 hours during which the boiler is operating at a steady state at least 90 percent of full load; and PLR-139362-14 9

(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 feedstock coal and refined coal used in the most recent determination that meets the requirements of the Notice.
Section 6.05 of the Notice provides that the certification requirement of section 3.01(1)(c) of the Notice is satisfied with respect to fuel for which the refined coal credit is claimed only if the taxpayer attaches to its tax return on which the credit is claimed a certification that contains the following: (1) a statement that the fuel will result in a qualified emissions reduction when used in the production of steam; (2) a statement indicating whether CEMS field testing was used to determine the emissions reduction;
PLR-139362-14 10

(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.” Finally, section 45(d)(8) of the Code provides that a refined coal production facility must be placed in service within certain timeframes. For purposes of the refined coal credit allowable with respect to refined coal other than steel industry fuel, the facility must be placed in service after October 22, 2004 and before January 1, 2012.
Section 3.07 of Notice 2010-54 provides that the year in which property is placed in service is determined under the principles of § 1.46-3(d) of the regulations; i.e., when the property is placed in a condition or state of readiness and availability for a specifically assigned function. Section 5.02 of Notice 2010-54 provides that a refined coal production facility will not be treated a placed in service after October 22, 2004 if more than 20 percent of the facility’s total value (the cost of the new property plus the value of the used property) is attributable to property placed in service on or before October 22, 2004. Notice 2010-54 also states that the IRS will not issue private letter rulings relating to when a refined coal production facility has been placed in service.
With respect to the first issue, the Process starts with several chemical additives being added to the feedstock coal prior to its combustion in a furnace. The additives provide the chemical structure that results in the reduction of emissions of nitrogen oxide and mercury during combustion. Section 6.01 of the Notice provides generally that a qualified emissions reduction does not include any reduction attributable to mining processes or processes that would be treated as mining if performed by the mine owner or operator. In the instant case, the Process is not a mining process.
Further, section 3.01 of the Notice clarifies §45(c)(7) of the Code and specifically provides that refined coal includes feedstock coal mixed with additives. Thus, additive processes that mix certain chemicals or other additives with the coal in order to achieve emissions reductions may qualify for the refined coal production tax credit. Additionally, section 3.03 defines comparable coal as coal that is of the same rank as the feedstock coal and that has an emissions profile comparable to the emissions profile of the feedstock coal. Accordingly, we conclude that the coal produced by using the Process constitutes a “refined coal” within the meaning of §45(c)(7) of the Code, provided that the refined coal (i) is produced from feedstock coal that is the same source or rank as the “Tested Coal” and (ii) satisfies the qualified emission reduction test stated in §45(c)(7)(B) of the Code.
With respect to the second issue, the emissions profile of the refined coal product is compared to the emissions profile of either the feedstock coal or a comparable coal PLR-139362-14 11 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 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 ranks as the Tested Coal, all feedstock coal that satisfies that criteria shall be treated as feedstock coal of the same source and rank for purposes of section 6.04 of Notice 2010-54, regardless of the mines from which such feedstock coal is purchased.
With respect to the third issue, section 6.03(3) of the Notice provides that any permissible testing method provided for in the Notice can be used in emission testing for any pollutant. That is, a taxpayer can use different testing methods for each of nitrogen oxide, sulfur dioxide or mercury, provided the method used for any pollutant is a permissible method. Section 6.04(1) provides that an emission test establishing a “qualified emission reduction” qualifies the refined coal for a six-month period provided there is no change in the process for producing the refined coal or in the source or rank of the feedstock coal. Therefore, a taxpayer must “redetermine” the emission reductions to qualify for the succeeding six-month period using one or more approved methods. In the instant case, Taxpayer 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, Taxpayer 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 facility, the Center has conducted pilot-scale combustion tests at its CTF as documented in the Test Reports. In conducting such tests, the Center conducted tests on the feedstock, and then mixed a separate sample of the feedstock with the additives so that it could conduct tests on the refined coal product. In each of its reports, the Center reported that the test results indicated that the blend of coal and additives achieved the required emissions reductions. Based on the foregoing, we conclude that testing by the Center for qualified emissions reductions as set forth in its test reports (including interim reports) satisfies the requirements of Notice 2010-54. Qualified emissions reduction through testing by the Center at its combustion research facility or similar pilot-scale combustion testing facilities under Notice 2010-54 may be relied upon.
PLR-139362-14 12
With respect to the fourth issue, section 6.04(2) of Notice 2010-54 provides, in part, that in the case of a redetermination required because of a change in the process of producing refined coal from the feedstock coal, the redetermination required under section 6.04 must use a method that meets the requirements of section 6.03. In any other case, the redetermination requirement may be satisfied by laboratory analysis 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 Taxpayer may satisfy the redetermination requirement of section 6.04 of Notice 2010-54, 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 below the bottom of (nor more than ten percent above the top of) the range of sulfur content and the range of 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.
With respect to the fifth issue, it is intended that Taxpayer will engage in redetermination testing every six months, or more frequently if required pursuant to Notice 2010-54. However, the Center is not always able to issue the written report required by section 6.03(2)(a) of Notice 2010-54 within the six month period. Thus, although redetermination testing is completed within the six month period, the report may be received after the six month period. Nonetheless, the Center informs Taxpayer of the results of the test shortly after the tests so that it is able to take into account the results of the redetermination within the six month period. Nevertheless, the delay by the Center in issuing its report cannot be indefinite. Accordingly, we conclude that the results set forth by the Center in a redetermination test report for production may be relied upon after the date of testing even if the report is not received until after the sixmonth period specified in section 6.04(1)(i) of Notice 2010-54, so long as Taxpayer receives the written report within 90 days from the date of testing. The new six-month period will begin on the date the redetermination was completed not the date of receipt of the report.
With respect to the sixth issue, each of the facilities was relocated from State B to State D, and during the life of the facilities, Taxpayer may decide to relocate a facility again, and it may be necessary to replace certain major components. In the event of relocation or replacement of a component, there should be no change in the placed in service date of the facility as long as the test described in section 5.02 of Notice 2010-54 has been met. Based on the foregoing, we conclude that provided a facility was “placed in service” prior to January 1, 2012, within the meaning of §45(d)(8), relocation of a facility to a different location after December 31, 2011, or replacement of part of a facility after that date, will not result in a new placed in service date for the facility for purposes of §45 provided the fair market value of the used property is more than twenty percent of the facility’s total value (the cost of the new property plus the value of the used property) at the time of relocation or replacement.
PLR-139362-14 13
With respect to the seventh issue, as discussed above, §45(d)(8) provides that a refined coal facility must be placed in service within certain time frames. Section 3.07 of Notice 2010-54 provides that the year in which property is placed in service is determined under the principles of Treas. Reg. §1.46-3(d); i.e., when the property is placed in a condition or state of readiness and availability for a specifically assigned function. The placed in service language of §45(d)(8) focuses on the facility and does not, by its terms, require the facility to have been placed in service by the entity that owns and operates the facility (and claims the credit for such production) at a later date.
Accordingly, we conclude that a change in ownership of the facilities subsequent to their placed-in-service dates will not affect the placed-in-service dates of the facilities for purposes of §45.
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 that 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)