Desert Sunlight 250, LLC v. United States

CORRECTED

In the United States Court of Federal Claims

No. 17-1826 T

Filed: October 8, 2021

Re-issued: November 2, 20211

)

DESERT SUNLIGHT 250, LLC and DESERT )

SUNLIGHT 300, LLC, )

)

Plaintiffs, )

)

v. )

)

THE UNITED STATES, )

)

Defendant. )

)

Steven J. Rosenbaum, Covington & Burling LLP, Washington, D.C., for Plaintiff.

Dennis B. Auerbach, Sean M. Akins, Alexis N. Dyschkant, and Seth A. Mohney, of counsel.

Matthew D. Lucey, United States Department of Justice, Tax Division, Court of Federal

Claims Section, Washington, D.C., with whom were Richard E. Zuckerman, Principal Deputy

Assistant Attorney General, David I. Pincus, Chief, Court of Federal Claims Section, G. Robson

Stewart, Assistant Chief, Court of Federal Claims Section, and Jason S. Selmont and Katherine

Powers, Trial Attorneys, of counsel, for Defendant.

OPINION AND ORDER

MEYERS, Judge.

To encourage investment, Section 1603 of the American Recovery and Reinvestment Act

of 2009 (“Section 1603”) provided cash grants to reimburse the cost of placing in service certain

renewable energy properties. Here, Plaintiffs acquired and applied for Section 1603 grants for

the Desert Sunlight solar energy project in California (the “Project”), which the Government

largely approved and awarded the Plaintiffs $550 million in grants. But the Government did not

approve $59 million of Plaintiffs’ application, and Plaintiffs sued to recover this $59 million.

The Parties have cross moved for summary judgment and the Government has filed a motion in

limine to strike certain statements in Plaintiffs’ declarations.

1

The Court issued this opinion under seal and directed the Parties to confer and propose any

redactions pursuant to the protective order. Because the Parties advise that no redactions are

necessary, the Court re-issues this opinion in full.

The Government moves for summary judgment arguing that the Plaintiffs have not

produced the required allocation of the consideration they paid for Desert Sunlight among all the

assets Plaintiffs acquired. While the Plaintiffs did not submit their allocation on an IRS Form

8594, whether they provided sufficient information to support their claim is a factual issue that is

not amenable to resolution on summary judgment. Therefore, the Court denies the

Government’s motion insofar as it seeks judgment ending this case.

In the alternative, the Government seeks summary judgment on several legal questions

about how assets should be categorized. Plaintiffs also seek summary judgment on these

questions and several more. For the reasons explained below, these motions are granted-in-part

and denied-in-part.

Finally, the Government has moved to strike certain statements in Plaintiffs’ witness

declarations because they are either legal conclusions, hearsay, or the declarant has not laid the

foundation for the challenged statements. Because none of the challenged statements are

necessary for the resolution of the summary judgment motions, the Court does not consider them

and denies the Government’s motion in limine as moot without prejudice to raise these

objections at trial.

I. Background

A. The Desert Sunlight Facility, the LGIA, and the PPAs

The Desert Sunlight Facility (the “Facility”) is a massive solar energy power plant

located in California’s Mohave Desert. Brannen Decl. ¶ 10 (ECF No. 86-3 at App’x 5).2 Sitting

on a site roughly 20% of the area of Manhattan, the Facility occupies an area approximately 3.2

miles by 2.6 miles. Id. ¶ 11. Prior to the Facility, nobody had undertaken building a solar

energy facility of similar size. Id. ¶ 20. As a solar photovoltaic (“PV”) electricity plant, the

Facility converts sunlight into electricity. Id. ¶ 12. It does so using solar panels, or “modules,”

to convert sunlight into direct current (“DC”) electricity. Id. ¶ 32. The Facility then uses

inverters to convert the DC electricity into alternating current (“AC”) electricity for delivery to

the utility transmission system. Id. (at App’x 21). As designed, the Facility’s DC generating

capacity was projected to be 724 megawatts of DC (“MWdc”). As built, the Facility has a

slightly greater 740.7 MWdc capacity. Id. ¶ 16. Its total AC generating capacity is

approximately 550 megawatts of alternating current (“MWac”). Id. The Facility is comprised of

two segments, a 250 MWac-capacity plant and a 300 MWac-capacity plant. Id. ¶ 17. Plaintiffs

Desert Sunlight 250, LLC and Desert Sunlight 300, LLC own the 250 MWac plant and the 300

MWac plant, respectively. ECF No. 1 ¶¶ 10-11. The Facility entered service in 2014. Brannen

Decl. ¶ 10.

2

As detailed more below, Mr. Brannen was NextEra’s Senior Director of Project Engineering

and Due Diligence. He served as a lead contract negotiator and oversaw the Plaintiffs’ team that

was on-site for the Desert Sunlight Facility’s construction.

2

Before the Facility’s construction, Plaintiffs were owned by First Solar, Inc. (“First

Solar”).3 ECF No. 1 ¶ 40. First Solar is a leading manufacturer of “thin film” solar modules,

which are widely used in solar PV facilities throughout the world. Brannen Decl. ¶ 15. First

Solar is also a leader in developing, financing, engineering, constructing, operating, and selling

many of the world’s largest grid-connected solar PV power plants. Id.; see also ECF No. 81-2 at

App’x 26. Before construction begins on a solar PV facility, the developer generally “execut[es]

an interconnection agreement” and “enter[s] into a power purchase agreement” (“PPA”). ECF

No. 81-2 at App’x 31. An interconnection agreement “is a contract in which a utility scale

electricity producer obtains the right to interconnect its facility to the electricity grid,” through

which it can then transport its electricity to the purchaser. Charles Decl. ¶ 9 (ECF No. 86-6 at

App’x 1127).4 “A PPA is a long-term contract in which an electricity producer agrees to sell

electricity to a utility or other customer pursuant to an agreed pricing formula[] . . . .” Id. First

Solar achieved both milestones as Plaintiffs’ owner while developing the Facility. Id.

In 2010, Plaintiffs entered into a Standard Large Generator Interconnection Agreement

(“LGIA”) with the Southern California Edison Company (“SCE”) and the California

Independent System Operator Corporation (“CAISO”). ECF No. 81-29 at App’x 2650, 2718-20.

Under the LGIA, Plaintiffs secured the right to interconnect the Facility to CAISO’s electricity

grid by way of SCE’s transmission system once the Facility became operational. Id. at App’x

2650, 2656-57, 2661-62. Also, Plaintiffs were responsible for building everything necessary to

connect the Facility to a substation that SCE was responsible for building. Id. at App’x 2722-23.

In other words, the SCE substation served as the handoff point of the Facility’s electricity to the

power grid; Plaintiffs were responsible for delivering electricity to the substation and SCE was

responsible for transporting it to the grid.

Plaintiffs also executed two PPAs for the output of the Facility. In 2009, Plaintiffs

executed a PPA with SCE. ECF No. 81-21; ECF No. 81-20 at App’x 2030. Under this PPA,

SCE agreed to purchase the total electrical output from DS 250 for 20 years. ECF No. 81-21 at

App’x 2062, 2071. And in 2010, Plaintiffs executed a PPA with Pacific Gas and Electric

Company (“PG&E”). ECF No. 81-22 at App’x 2299. Here, PG&E agreed to purchase the total

electrical output from DS 300 for 25 years. Id. at App’x 2324.

B. First Solar Sells the Facility to GE and NextEra

In 2011, First Solar began negotiating with NextEra Energy Resources, LLC (“NextEra”)

and GE Energy Financial Services (“GE”) to sell First Solar’s interest in Plaintiffs. Brannen

Decl. ¶ 13. NextEra builds and operates solar power facilities. Id. ¶¶ 7-8. GE is a financial

services provider with experience investing in the renewable energy industry. Id. ¶ 13.

3

The corporate entities to the transactions in this case acted through various subsidiaries.

Because the specific subsidiary entities are not relevant to the issues before the Court, the Court

refers to the parent entities for ease of reference unless otherwise indicated.

4

Prior to his retirement, Mr. Charles was a Senior Principal Consultant at Sargent & Lundy,

where he worked extensively on solar projects. Plaintiffs have retained Mr. Charles as an expert

witness.

3

On September 29, 2011, First Solar, NextEra, and GE executed several agreements,

including: (1) three Engineering, Procurement, and Construction (“EPC”) Agreements; (2) three

Operating and Maintenance (“O&M”) Agreements; (3) financing agreements; (4) a Department

of Energy (“DOE”) Loan Guarantee; and (5) a Membership Interest Purchase and Sale

Agreement (“MIPSA”).

1. The EPC Agreements and O&M Agreements

The three fixed-price EPC Agreements are contracts to engineer, procure, and construct

the Facility. Id. ¶ 14. The first EPC Agreement is between Plaintiff DS 250 and First Solar.

ECF No. 81-12. In this agreement, Plaintiff DS 250 hired First Solar to develop and construct

the 250 MWac portion of the Facility for a fixed price of $807,932,028. Id. at App’x 858, 904.

The second agreement is between Plaintiff DS 300 and First Solar, in which Plaintiff DS 300

hired First Solar to develop and construct the 300 MWac portion of the Facility for a fixed price

of $967,742,759. ECF No. 81-13 at App’x 1011, 1056. The third agreement is between both

Plaintiffs and First Solar, in which Plaintiffs hired First Solar to develop and construct the

common areas of the Facility for a fixed price of $175,132,299. ECF No. 81-15 at App’x 1666,

1702. The total price of all three EPC Agreements is $1,950,807,086. Plaintiffs contend that

this total includes approximately $104 million in sales tax. Brannen Decl. ¶¶ 21, 62.

The EPC Agreements’ terms underwent changes over the course of negotiations between

First Solar, NextEra, and GE, according to both NextEra’s lead negotiator, William Brannen, Id.

¶¶ 22-23, and First Solar’s Kent Draper, Draper Dep. Tr. at 28:7-8, 29:1-7, 265:13-17 (ECF No.

81-63 at App’x 4149, 4208). In the beginning of the negotiations, First Solar sought a total price

of over $2.36 billion for all three EPC Agreements, but NextEra and GE negotiated the final

price down by over $400 million to reach the final $1,950,807,086 total price. Brannen Decl. ¶

22; see also Draper Dep. Tr. 264:21-265:12. NextEra and GE also convinced First Solar to take

on greater risk than it originally accepted, such as the risk of increased cost of equipment,

material, and labor during the construction period, even though acceptance of greater risk

typically results in higher prices. Brannen Decl. ¶ 23; Draper Dep. Tr. 270:25-271:19, 273:1-7,

274:10-15. Mr. Brannen attributes the final deal to “the hard bargain that NextEra and GE

drove.” Brannen Decl. ¶ 23. Mr. Draper agreed. Draper Dep. Tr. 274:22-275:6. Indeed, Mr.

Draper testified that the negotiation “was . . . very arm’s length . . . it was an extremely hard

negotiation with GE and NextEra.” Id. at 265:13-17. Mr. Draper further testified that “they [GE

and NextEra] were tough negotiators. They’re, you know, extremely well-versed in . . . the

issues that we were dealing with, both on the technical side and risk allocation under EPC

agreements and . . . they drove a hard bargain.” Id. at 266:24-267:5.

Moreover, the negotiations concerned not just the total EPC Agreement prices but also

the price for specific components under each EPC Agreement. Brannen Decl. ¶¶ 18, 44. The

specific component prices were set forth in Exhibit I to all three EPC Agreements. ECF No. 88

at App’x 285 ¶ 12; see id. at App’x 353-360.

Exhibit I effectively has two parts. See Brannen Dep. Tr. at 75:9-76:8, 117:5-118:13

(ECF No. 81-6 at App’x 230, 240-41) (Mr. Brannen referring to the first part as the “schedule of

values” and the second part as the “milestone payment schedule.”). The first part contains

schedules of component pricing for each EPC Agreement. ECF No. 88 at App’x 353-56; see

4

also Pitale Decl. ¶¶ 12-13 (ECF No. 88 at App’x 285-86).5 In relevant part, as shown in the

excerpt below of the schedule of the DS 300 EPC Agreement’s component pricing, the schedules

list: (1) the EPC Agreement’s components (Milestones); (2) the quantity of components at which

they are priced (Unit of Measure); (3) the percentage of each unit’s price within the EPC

Agreement’s price (Milestone Value (% of Sale Price)); (4) each unit’s price (Milestone Value);

(5) the total number of units (Project Quantities); (6) the total cost for all of the units (Total

Project Value); and (7) the percentage of the total EPC Agreement price that each component

represents (Total Project %):

Id. ¶ 13; ECF No. 88 at App’x 355.

Exhibit I’s second part contains a payment schedule for each EPC Agreement. Pitale

Decl. ¶ 14. As shown in the excerpt of the DS 300 EPC Agreement’s payment schedule below,

the schedules list each monthly payment Plaintiffs would make to First Solar (Total EPC

Payment – Monthly), as well as the aggregate amount Plaintiffs have paid to First Solar up to

each month (Total EPC Payment – Cumulative):

5

Ms. Pitale is NextEra’s Senior Director of State Tax Policy. At the time of the Desert Sunlight

Transaction, she was a Senior Director of Tax at NextEra. She supervised the preparation of the

Section 1603 grant at issue in this case.

5

Id.; ECF No. 88 at App’x 359. Each monthly payment amount was simply calculated by

multiplying the number of component units expected to be completed that month by the price of

each component unit. See Brannen Dep. Tr. at 76:3-8 (ECF No. 81-6 at App’x 230).

In negotiating the EPC Agreements, Mr. Brannen states that he “was careful to ensure

that the price for the three EPC contracts standing alone was a fair-market price for the EPC

work that First Solar performed.” Brannen Decl. ¶ 24 (ECF No. 86-3 at App’x 12). Mr.

Brannen explains that he had multiple reasons to do so beyond pursuing NextEra’s normal

business objective of paying only fair market value for EPC agreements. Id. First, Mr. Brannen

states he knew that NextEra would require loans to pay for the EPC Agreements, and that banks

would not finance the EPC Agreements if they were above market. Id. Second, due in part to

the magnitude of the Facility’s construction, Mr. Brannen states he feared that First Solar may

not complete the Project, and that NextEra did not want to have paid First Solar an above-market

amount for any work already completed. Id. Third, Mr. Brannen states that he had a personal

incentive to reach the best price and lowest risk EPC Agreements because a significant portion of

his salary was an incentive payment tied to the deal reached. Id. ¶ 25. Mr. Draper also states

that First Solar was “trying to stay cash neutral or cash positive throughout the course of

construction for the project.” Draper Dep. Tr. at 252:8-12 (ECF No. 81-63 at App’x 4205).

The Parties also took several steps in assessing the EPC Agreement prices.

First, NextEra performed its own “cost build up,” which was reviewed by an independent

engineering firm, BEW. Brannen Decl. ¶ 26e. Excluding the cost of the EPC Agreements’

module and cartridge components, NextEra estimated the cost of the remaining components,

known as the balance of system (“BOS”) component cost, under the EPC Agreements to be

$1.04/Wdc, which BEW believed was low. Id. NextEra then compared its estimated $1.04/Wdc

BOS price to First Solar’s proposed BOS price of $1.21/Wdc and found that the prices were

similar. Id. Next Era viewed the $0.17/Wdc difference between the two prices as merely “a

reasonable markup for sales tax and for the overhead, profit and risk contingency that an EPC

contractor like First Solar would charge.” Id. Based on its knowledge of the solar modules

market, NextEra further determined that the EPC Agreement prices for modules and cartridge

were also fair market value, and that their percentage of the cost of the EPC Agreements was

standard as well. Id. ¶¶ 26e, 53-56. Accordingly, NextEra concluded that the EPC Agreement

prices were fair market value. Id. ¶ 26e.

6

Second, First Solar, at the direction of Goldman Sachs (one of NextEra and GE’s lenders

funding the EPC Agreements), requested that an independent engineering firm, Black & Veatch

Corporation (“Black & Veatch”), assess the Project. ECF No. 88 at App’x 257. Black & Veatch

concluded that “the total construction cost is consistent with the total construction cost of other

PV solar generating facilities utilizing the same technology and with our understanding of

current market pricing in the solar PV industry.” Id. at App’x 258.

Third, NextEra consulted Treasury guidance “reflect[ing] that a cost of $4/W to build

the . . . property for a utility-scale solar PV facility was presumptively reasonable.” Brannen

Decl. ¶ 26d (ECF No. 86-3 at App’x 14). Specifically, the guidance provided that, as of the first

quarter of 2011, its benchmark price to construct such facilities was $4 per watt (“/W”).6 Id.; see

also ECF No. 88 at App’x 250. According to the guidance, the benchmarks reflect a property’s

fair market value and “are predicated on an open-market, arm’s-length transaction between two

entirely unrelated parties with adverse economic interests.” ECF No. 88 at App’x 249-50. In

contrast to the $4/W price, Mr. Brannen calculated that the EPC Agreements’ total price of over

$1.9 billion “translates to a price of $2.69 per watt of DC capacity based on the facility’s original

planned capacity of 724 MWdc, . . . $2.63/Wdc based on actual as-built capacity of 740.7

MWdc[, and,] [i]ncluding net early completion bonuses . . . , $2.73/Wdc based on Desert

Sunlight’s as-built capacity of 740.7 MWdc.” Brannen Decl. ¶ 21. In contrast to Mr. Brannen’s

calculations, Ms. Angela Pitale, NextEra’s Senior Director of Tax from 2011-2015, calculated a

price of $2.77/Wdc. Pitale Decl. ¶ 59 (ECF No. 88 at App’x 315).

Fourth, Mr. Brannen was aware that various public reports estimated the EPC agreement

prices of typical utility-scale solar PV facilities, and that his estimated prices of $2.63/Wdc or

$2.73/Wdc for the Facility’s EPC Agreements was lower than all of them. Brannen Decl. ¶ 26c.

For example, the Solar Energy Industry Association’s (“SEIA”) 2011 First Quarter U.S. Solar

Market Insight publication estimated the average utility-scale solar PV facility system price in

the first quarter of 2011 to be $3.85/W. ECF No. 88 at App’x 222. And a National Renewable

Energy Laboratory’s (“NREL”) February 2011 report estimated a utility-scale solar PV facility

system price at the end of 2010 to be approximately $4/Wdc. Id. at App’x 239.

Apparently satisfied that the Facility’s total cost was reasonable, the Parties signed the

EPC Agreements. Plaintiffs and First Solar also entered into three O&M Agreements, under

which Plaintiffs hired First Solar to provide operations and maintenance services for the 250

MWac portion, the 300 MWac portion, and the common facilities of the Facility, respectively.

See ECF Nos. 81-16, 81-17, & 81-18.

2. Financing Agreements and the DOE Loan Guarantee

As part of its development of the Project, First Solar arranged Project financing terms

with several private banks. ECF Nos. 91-3, 91-4, 95-2 at App’x 2892-2900. At the time that

Plaintiffs acquired the Project, they also entered into financing agreements with these banks on

the terms First Solar arranged for loans of $1.461 billion. Brannen Decl. ¶ 94; Scarff Decl. ¶ 2

6

Mr. Brannen clarifies that “[i]t is unclear whether the Treasury benchmark number is $/Wdc or

$/Wac, but, either way, the Desert Sunlight number was lower.” Brannen Decl. ¶ 26d.

7

(ECF No. 95-2 at App’x 2865).7 According to Plaintiffs, they paid slightly less than $87 million

in interest on the loans during the construction of the Facility. Pitale Decl. ¶ 88. NextEra and

GE used equity to finance more than $600 million that they did not finance through the loans.

Brannen Decl. ¶ 94; ECF No. 81-60 at App’x 3982.

The Department of Energy also provided a loan guarantee8 covering 80% of the loans—

$1,168,800,000—in case Plaintiffs defaulted. Brannen Decl. ¶ 94. The DOE Loan Guarantee

was made pursuant to Section 1705 of Title XVII of the Energy Policy Act of 2005, Pub. L. No.

109-58, § 1705, 119 Stat. 594, which the American Recovery and Reinvestment Act of 2009

added to Title XVII to create a temporary program permitting DOE to issue loan guarantees in

support of renewable energy projects. ECF No. 81-65 at App’x 2571.

Before providing the guarantee, DOE took multiple steps to assess First Solar’s total EPC

price, which was then over $2.36 billion. DOE conducted its own due diligence and determined

that there was a reasonable assumption that, based on the proposed total EPC Agreement price,

the loan would be repaid. Walker Dep. Tr. at 99:8-14 (ECF No. 88-1 at App’x 2816).9 It did so

by comparing the proposed total EPC Agreement price to other projects in its internal databases.

Id. at 103:16-17. DOE then engaged in interagency discussions with Treasury, which was

concerned that the proposed total EPC Agreement price was too high in comparison to several

other projects. Id. at 44:18-45:11, 59:2-8. Specifically, in June 2011—before the more than

$400 million reduction from First Solar’s proposed total EPC Agreement price and before the

Facility was built with a 740.7/MWdc generating capacity—the total EPC Agreement price was

proposed by First Solar at $2.97/Wdc (including labor adjustments), and Treasury indicated that

a comparable EPC agreement price would be $2.80/Wdc without labor adjustments and

$2.92/Wdc with labor adjustments. Id. at 154:21-158:3; see also ECF No. 88-1 at 2863. To

assuage Treasury’s concerns, DOE consulted numerous experts for their assessment of the

proposed total EPC Agreement price. Walker Dep. Tr. at 46:17-47:17.

The Loan Programs Office (“LPO”), which provides DOE’s loan guarantees, requested

the analysis from DOE’s Solar Energy Technology Program (“SETP”). ECF No. 88-1 at App’x

2425; Ramesh Dep. Tr. at 23:21-25:12 (ECF No. 88-1 at App’x 2364).10 In response to the

LPO’s request, SETP coordinated with the NREL, one of the seventeen national labs within

DOE, to conduct its review using the NREL’s solar PV cost estimating tool—bottom-up cost

modeling. Ramesh Dep. Tr. at 17: 13-16, 25:1-17. Bottom-up cost modeling is a method used to

determine a project’s cost based on its various components, which in turn is based on market

7

During the negotiations regarding the Desert Sunlight acquisition, Mr. Scarff was a project

manager and was involved in those negotiations.

8

In fact, there were multiple loan guarantees that cover various loans. Scarff Decl. ¶ 6. Because

the disputes involving the guarantees only address them in the aggregate, the Court does so as

well.

9

Mr. Walker is an employee of the U.S. Department of Energy in the Loan Programs Office. He

was involved in the Department’s due diligence regarding the loan guarantee for Desert Sunlight.

10

Dr. Ramesh formerly served in the Department of Energy and performed or oversaw the due

diligence of the Desert Sunlight Transaction.

8

surveys in consultation with industry stakeholders. Ramesh Dep. Tr. at 19:24-20:12, 34:18-35:3.

Upon completion of the SETP/NREL review, the SETP’s Program Manager, Dr. Ramesh, issued

a memorandum to the LPO that concluded that First Solar’s proposed total EPC Agreement price

is “below the current estimated average total project cost for comparable projects and [is] within

a reasonable range of the expected system price, as estimated using NREL’s internal solar PV

cost estimating tool” (i.e., the bottom-up cost model). ECF No. 88-1 at App’x 2425; Ramesh

Dep. Tr. at 25:13-17; see also ECF No. 88-1 at App’x 2420 (another DOE memorandum

concluding that “[b]ased on this analysis the EPC price falls within an acceptable range of

expected system costs based on technology selection, system size and configuration.”).

Specifically, the NREL determined that First Solar’s then-proposed total EPC Agreement price

of $3.43/Wdc was within a reasonable range of the NREL’s estimated EPC system price for a

project similar to the Desert Sunlight Facility of $2.93/Wdc. ECF No. 88-1 at App’x 2427-28;

Ramesh Dep. Tr. at 129:16-21. Dr. Ramesh explains that the memorandum compared the

proposed total EPC Agreement price to the NREL’s 2010 Q4 Benchmark of $4.13/Wdc, not the

NREL’s estimated price of $2.93/Wdc. Ramesh Dep. Tr. at 40:18-41:5. Further, Dr. Ramesh’s

memo states that “[w]e have compared a detailed break out of the pricing for the elements of the

EPC contract against our model and have found the pricing to be within our expected range.”

ECF No. 88-1 at App’x 2426.

In addition to its internal resources, DOE consulted three outside, independent

engineering firms to assess the proposed total EPC Agreement price. Walker Dep. Tr. 46:17-

47:17 (ECF No. 88-1 at App’x 2803). The first firm was Luminate, LLC (“Luminate”), which

concluded that both First Solar’s initial EPC Agreement price and the final EPC Agreement price

were reasonable. Grover Dep. Tr. at 17:20-18:7, 79:20-81:18 (ECF No. 81-36 at App’x 3181-82,

3197).11 The second firm, Burns and Roe Enterprises, Inc., also concluded that the proposed

EPC Agreement prices were reasonable. Walker Dep. Tr. at 53:16-22, 58:16-59:18 (ECF No.

88-1 at App’x 2804, 2806). The third firm DOE consulted was Shaw Consultants International,

Inc. Id. at 69:9-71:6, 75:23-76:4; ECF No. 88-1 at App’x 2556-76. Shaw defined a “fair market

value” price as “one where the price is comparable to an EPC price that was obtained through a

competitive third party EPC solicitation for comparable PV projects.” Id. at App’x 2560. Based

on its analyses, Shaw determined that the Facility’s total EPC Agreement price was the cheapest

of seventeen solar facility EPC prices considered. Id. at App’x 2573. Shaw thus concluded that

the EPC Agreement prices were fair market values. Id. at App’x 2576. In addition, Shaw

concluded that the Facility’s EPC Agreement price was “comparable to ‘arm’s length’ or third

party EPC prices.” Id.; see also Walker Dep. Tr. at 92:4-94:18.

After consulting these experts, DOE ultimately issued the Loan Guarantee.

3. The MIPSA

Lastly, First Solar, NextEra, and GE also executed the MIPSA, through which First Solar

sold its entire interest in Plaintiffs to NextEra and GE. ECF No. 81-10 at App’x 333. Included

in the sale was the LGIA, the two PPAs, and the DOE Loan Guarantee. Id. Under the MIPSA,

11

Ms. Grover is a senior vice president of Luminate.

9

NextEra and GE each paid First Solar $7,222,803, for a total price of $14,445,606. Id. at App’x

351.

The EPC Agreement and MIPSA prices were arrived at using a “Project Model,” an

intricate, multi-tab Excel spreadsheet aimed at calculating the Transaction’s prices based on the

Facility’s expected return on equity (“ROE”) for the purchasers (NextEra and GE). See id. at

App’x 351-52; see also ECF No. 81-25 (Project Model Cover Sheet) and related CD (Project

Model). As explained in NextEra’s summary of the Facility’s transaction, the Project Model

calculates the expected ROE by considering various factors, including “expected debt terms,

plant performance (energy output, availability during the O&M phase), interconnection

energization date, energization dates for the 20 blocks (ramp revenues), substantial completion

date and PPA commercial operation dates (COD), future operating, certain owner costs and

future maintenance expenses.” ECF No. 81-19 at App’x 2013. The MIPSA sets forth the

limited conditions and procedures warranting revising the input into the Project Model, see ECF

No. 81-10 at App’x 351-53, as otherwise “the calculations embedded in the Project Model will

not be changed or revised for any reason, including the discovery of a mathematical or formulaic

error in the Project Model,” id. at App’x 352.

Following the execution of all the agreements, First Solar began constructing the Facility.

Given the scale of the Project, First Solar constructed the Facility in phases, known as “blocks.”

Pitale Decl. ¶ 16. The Facility was constructed in twenty blocks. Id. Blocks 1-11 comprised the

300MWac portion and Blocks 12-20 comprised the 250 MWac portion. Id.

C. The American Recovery and Reinvestment Act of 2009

“Congress has long used tax incentives to promote investment in new renewable energy

projects.” Alta Wind I Owner Lessor C v. United States, 897 F.3d 1365, 1368 (Fed. Cir. 2018).

“Initially, these incentives came in the form of tax credits—specifically the production tax

credit . . . under I.R.C. § 45 and the investment tax credit . . . under I.R.C. § 48.” Id. By 2009,

however, the Great Recession had reduced the benefit of these tax credits. Id. In response to

economic problems, Congress passed the American Recovery and Reinvestment Act of 2009

(“ARRA”). Pub. L. No. 111-5, 123 Stat 115 (2009). “The ARRA created a temporary program

that offered a cash payment in lieu of a tax credit to certain investors for certain qualified

investments in clean energy property.” WestRock Virginia Corp. v. United States, 136 Fed. Cl.

267, 270 (2018), aff'd, 941 F.3d 1315 (Fed. Cir. 2019). Specifically, Section 1603(a) provides

that “[u]pon application, the Secretary of the Treasury shall . . . provide a grant to each person

who places in service specified energy property to reimburse such person for a portion of the

expense of such property.” “Specified energy property” includes certain solar property. §

1603(d)(3). And the amount of the cash grant is the “applicable percentage of the basis of such

property,” which is 30% for solar property. § 1603(b)(1)-(2). “It is intended that the grant

provision mimic the operation of the credit under [IRC] section 48.” WestRock Virginia Corp.,

941 F.3d at 1316 (quoting H.R. Rep. No. 111-16, at 620–21 (2009)) (alteration in original).

D. Plaintiffs’ Section 1603 Applications

As First Solar constructed and placed into service the blocks of the Facility, Plaintiffs

submitted applications (fifteen in total) to Treasury for cash grants under Section 1603. Pitale

10

Decl. ¶ 16. Plaintiffs’ fifteen applications concerned a total of approximately $2.13 billion in

expenses incurred to place into service the Facility, of which Plaintiffs contend $2,049,419,165

is Section 1603-eligible. Id. ¶ 17. According to Plaintiffs, the almost $2.05 billion was mainly

comprised of the costs under the EPC Agreements, including sales tax. See id. ¶ 22.

In addition to the EPC costs, Plaintiffs concluded that certain other costs were Section

1603-eligible. First, Plaintiffs assert that the almost $87 million in interest paid to lenders during

the construction of the Facility is Section 1603-eligible. Id. ¶ 89. Second, they also contend that

approximately $72 million in net bonuses paid to First Solar for early completion of certain

blocks of the Project is 1603-eligible. Brannen Decl. ¶¶ 63-64. And third, Plaintiffs argue that

additional miscellaneous costs including reimbursements to First Solar under the MIPSA for

development costs it incurred before transacting with NextEra and GE are Section 1603-eligible.

Brannen Decl. ¶ 67. In sum, Plaintiffs’ applications claimed entitlement to a Section 1603 cash

grant of $614,825,750 (i.e., the 30% applicable percentage of the $2,049,419,165 eligible basis).

ECF No. 1 ¶ 45.

With each of their applications, Plaintiffs submitted a cost segregation of that

application’s expenses. Pitale Decl. ¶ 20. A cost segregation is a document that assigns

expenses to distinct categories. O’Connell Decl. ¶ 6 (ECF No. 86-6 at App’x 1249).12 Plaintiffs’

cost segregations categorized their application’s expenses among direct costs and indirect costs

(costs necessary to acquire and install tangible property) and between claimed Section 1603

grant-eligible and grant-ineligible expenses. Pitale Decl. ¶ 34. In addition, after submitting the

fifteen applications and accompanying cost segregations, Plaintiffs submitted to Treasury a

single document in Excel format, the Total Cost Spreadsheet, which comprises all the cost

segregations on individual tabs. Id. ¶¶ 46-47. The Total Cost Spreadsheet also has a tab called

the Total Project Cost Summary, which is the summary page of the Total Cost Spreadsheet. Id. ¶

48. For each application, the Total Project Cost Summary presents the total cost reported on

each application and the total eligible cost Plaintiffs claimed on each application. Id. ¶¶ 48-49.

Moreover, the last row of the tab provides the total reported Project cost of $2,129,201,444.90

and the total claimed Section 1603-eligible cost for the Project of $2,049,419,162.17. Id. ¶ 49.

Plaintiffs worked with KPMG, LLP, and principally with Mark O’Connell of KPMG, to

create the cost segregations. O’Connell Decl. ¶ 4 (ECF No. 86-6 at App’x 1249). Mr.

O’Connell explained that KPMG’s work preparing the cost segregations involved numerous

steps. KPMG first categorized costs between direct and indirect costs. Id. ¶¶ 26-33. Mr.

O’Connell segregated which direct costs were, in his opinion, Section 1603-eligible costs and

which were Section 1603-ineligible costs. Id. ¶ 34. But before determining whether the costs for

certain asset components were Section 1603-eligible, Mr. O’Connell had to first determine the

component costs because only the larger asset cost was known. For example, Mr. O’Connell

calculated the prices of components falling under the larger “substation” cost (the costs incurred

to construct the onsite substation at the Facility). Id. ¶ 41. Mr. O’Connell specifically allocated

the total price of the substation to its individual components based on benchmarking information

from other projects. Id. Mr. O’Connell similarly calculated the prices of components in the

larger cost category of “FNTP/Site Improvements,” which he divided into sub-categories labeled

12

Mr. O’Connell worked at KPMG and prepared the cost segregations for the Project.

11

“General Conditions” and “Buildings/Roads.” Id. ¶ 49. Primarily utilizing the Marshall & Swift

manual, which “contains price figures for various construction related expenses,” Mr. O’Connell

allocated the total price of the “FNTP/Site Improvements” to its individual components. Id. ¶¶

52-53. Reflecting on these analyses, Mr. O’Connell concluded that “[t]he cost analyses that my

team performed on the substation, the General Conditions site improvements category, and the

Buildings/Roads site improvements category covered over 99% of the ineligible direct EPC

costs, after excluding the gen-tie line, that Plaintiffs had incurred at the time of the analyses.” Id.

¶ 61. In addition, Mr. O’Connell determined that the “Gen-Tie” costs (for the construction of the

generation tie line, or transmission line, from the Facility’s on-site substation to a utility

company’s offsite substation) were Section 1603-ineligible costs. Id. ¶ 38.

Plaintiffs also hired Deloitte & Touche LLP to issue the accountant reports attesting to

the accuracy of the applications, which Treasury required. Pitale Decl. ¶¶ 30, 41. After

receiving all requested documentation, Deloitte examined the cost segregations. Id. ¶¶ 41-42.

Specifically, Deloitte tested “whether the claimed costs were in fact incurred and paid, and

whether the costs were properly classified as direct or indirect, and eligible or ineligible” in its

opinion. Id. ¶ 42. Deloitte concluded its examination by issuing an independent accountant’s

report for each application verifying it was “fairly stated, in all material respects.” Id.

After reviewing the applications, Treasury awarded Plaintiffs a Section 1603 cash grant

of approximately $555,506,250—$59,319,500 less than Plaintiffs’ requested amount of almost

$615 million, as broken down in the following table:

Block Installation Owner Grant Sought Grant Issued Difference

(Pre-Sequestration) (Pre-Sequestration)

Blocks 1, 2, 10, 11 DS 300 $148,798,318 $129,309,750 $19,488,568

Blocks 16, 17, 20 DS 250 $95,021,918 $77,347,500 $17,674,418

Block 3 DS 300 $41,149,028 $38,436,750 $2,712,278

Block 4 DS 300 $30,906,856 $29,014,500 $1,892,356

Block 12 DS 250 $41,478,228 $38,343,000 $3,135,228

Block 13 DS 250 $41,448,054 $38,530,500 $2,917,554

Block 14 DS 250 $28,149,884 $26,564,250 $1,585,634

Block 19 DS 250 $26,720,334 $26,160,000 $560,334

Block 18 DS 250 $30,329,825 $28,875,000 $1,454,825

Block 15 DS 250 $15,250,665 $14,392,500 $858,165

Block 5 DS 300 $25,935,287 $24,390,000 $1,545,287

Block 6 DS 300 $26,060,838 $24,397,500 $1,663,338

12

Block 7 DS 300 $20,828,189 $19,680,000 $1,148,189

Block 8 DS 300 $19,475,260 $18,337,500 $1,137,760

Block 9 DS 300 $ 23,273,066 $21,727,500 $1,545,566

Total $614,825,750 $555,506,250 $59,319,500

See id. ¶ 122; see also ECF No. 1 ¶ 49.

II. Standard of Review

“The [C]ourt shall grant summary judgment if the movant shows that there is no genuine

dispute as to any material fact and the movant is entitled to judgment as a matter of law.” RCFC

56(a). “By its very terms, this standard provides that the mere existence of some alleged factual

dispute between the parties will not defeat an otherwise properly supported motion for summary

judgment; the requirement is that there be no genuine issue of material fact.” Anderson v.

Liberty Lobby, Inc., 477 U.S. 242, 247-48 (1986) (emphasis in original). A “genuine” dispute of

material fact exists where a reasonable factfinder “could return a verdict for the nonmoving

party.” Id. at 248. “Material” facts are those “that might affect the outcome of the suit under the

governing law,” as opposed to “disputes that are irrelevant or unnecessary.” Id. “When both

parties move for summary judgment,” moreover, “the [C]ourt must evaluate each party’s motion

on its own merits, taking care in each instance to draw all reasonable inferences against the party

whose motion is under consideration.” AT&T Advertising, L.P. v. United States, 147 Fed. Cl.

478, 482 (2020) (citing Mingus Constructors, Inc. v. United States, 812 F.2d 1387, 1391 (Fed.

Cir. 1987)).

In addition, as in tax refund cases, the Court reviews claims against the Government for

Section 1603-cash-grant reimbursements de novo. W.E. Partners II, LLC v. United States, 119

Fed. Cl. 684, 690 (2015).

III. Discussion

A. The Government’s Motion in Limine

Before reaching the motions for summary judgment, the Court must address the

Government’s motion in limine to exclude various testimonial evidence Plaintiffs submitted to

support their summary judgment briefing. ECF No. 92. Because none of the challenged

statements are necessary for the resolution of the cross motions for summary judgment, the Court

does not consider them.13 Therefore, the Government’s motion in limine is denied as moot

without prejudice to objecting at trial.

13

To be clear, the Court does cite a few paragraphs in which the Government challenges portions

of those paragraphs. The Court only refers to the unchallenged statements in those paragraphs.

13

B. The Government’s Motion for Summary Judgment

The Government moves for summary judgment on the ground that Plaintiffs cannot meet

their burden of proof to establish entitlement to the Section 1603 grant they seek because they

have not produced (and cannot now produce) the required allocation of the price of the Desert

Sunlight Transaction14 under 26 U.S.C. § 1060 on IRS Form 8594. ECF No. 80 at 32. Plaintiffs

counter that they produced their allocation of the Transaction price, albeit not on IRS Form 8594,

which they argue contains far more information about their allocation than a Form 8594. ECF

No. 86-1 at 67. Plaintiffs also explain that they did not file a Form 8594 because at the time of

their filing they did not understand that Section 1060 governed the Desert Sunlight Transaction

when they originally applied for a Section 1603 grant. Id. at 67 n.9. Based on Alta Wind, which

was decided years later in 2018, all now agree that Section 1060 applies. See 897 F.3d at 1376.

And Plaintiffs note that the penalty for failing to file a Form 8594 is a mere $250 fine, making a

forfeiture of their claim now unreasonable. ECF No. 86-1 at 67 (citing 26 U.S.C. §§ 6721(a)(1),

6724(d)(1)(B)(xvii)).

Putting this aside, there are significant, material issues in dispute, which preclude

summary judgment for the Government.

1. The Legal Framework of an I.R.C. § 1060 Allocation.

I.R.C. § 1060 governs the purchaser’s cost basis in “applicable asset acquisition[s].”

I.R.C. § 1060(a). An “applicable asset acquisition” refers to any transfer “of assets which

constitute a trade or business.” I.R.C. § 1060(c)(1). As relevant here, Treasury Regulations

define a “trade or business” as a group of assets whose “character is such that goodwill or going

concern value could under any circumstances attach to such group.” 26 C.F.R. § 1.1060-

1(b)(2)(i)(B). “Goodwill is the value of a trade or business attributable to the expectancy of

continued customer patronage.” 26 C.F.R. § 1.1060-1(b)(2)(ii). “Going concern value is the

additional value that attaches to property because of its existence as an integral part of an

ongoing business activity.” Id. The regulations further provide that, in determining whether

goodwill or going concern value could attach, “all the facts and circumstances surrounding the

transaction are taken into account,” including:

(A) [t]he presence of any intangible assets . . . ; (B) [t]he existence

of an excess of the total consideration over the aggregate book

value of the tangible and intangible assets purchased . . . ; and (C)

[r]elated transactions, including lease agreements, licenses, or

other similar agreements between the purchaser and seller . . . in

connection with the transfer.

26 C.F.R. § 1.1060-1(b)(2)(iii).

14

The term “Desert Sunlight Transaction” or “Transaction” used in this section refers

specifically to the EPC Agreements and the MIPSA, as all the relevant Section 1603-eligible

assets were transferred from First Solar to NextEra and GE through these two agreements.

14

For transfers of such applicable asset acquisitions, “the transferee’s basis in such assets is

determined wholly by reference to the consideration paid for such assets.” I.R.C. § 1060(c)(2).

Specifically, “the consideration received for such assets shall be allocated among such assets

acquired in such acquisition in the same manner as amounts are allocated to assets under section

338(b)(5).” I.R.C. § 1060(a). I.R.C. § 338(b)(5) provides that allocation is to be done according

to Treasury regulations. These regulations direct purchasers to “allocate the consideration under

the residual method as described in [26 C.F.R.] §§ 1.338-6 and 1.338-7 in order to determine . . .

the basis in[] each of the transferred assets.” 26 C.F.R. § 1.1060-1(a)(1); see also 26 C.F.R. §

1.1060-1(c)(2) (providing that the purchaser’s basis in the assets purchased in an applicable asset

acquisition requires allocating the consideration to all the assets purchased under the residual

method of 26 C.F.R. §§ 1.338-6 and 1.338-7).

Section 1.338-6 “set[s] out a method of allocation—the residual method—in which the

consideration is distributed among seven asset classes, some classes for tangible assets and

others for intangible assets.” Alta Wind, 897 F.3d at 1376. Those asset classes are:

Class I: Cash and general deposit accounts.

Class II: Actively traded personal property, certificates of deposits, U.S.

government securities and publicly traded stock.

Class III: Debt instruments [(including accounts receivable)].

Class IV: Inventory and other property held for sale to customers.

Class V: Assets that do not fit within any other class, including tangible property.

Class VI: I.R.C. § 197 intangibles, including contract rights, but not goodwill and

going concern value.

Class VII: Goodwill and going concern value.

Id. (citing 26 C.F.R. § 1.338-6(b)). “The consideration is allocated among these classes in the

order they are listed in a ‘waterfall’ fashion, using the fair market value of the assets within each

class.” Id. Also, “[t]he amount . . . allocated to an asset (other than Class VII assets) cannot

exceed the fair market value of that asset . . . .” 26 C.F.R. § 1.338-6(c)(1). Thus, the

consideration is first allocated to Class I assets up to their fair market value, then to Class II

assets up to their fair market value, and so on until the consideration is fully allocated. 26 C.F.R.

§ 1.338-6(b)(1)-(2).

Here, the Parties agree that I.R.C. § 1060 and the residual method apply to determine the

amount of a Section 1603 grant. ECF No. 80 at 21-23; ECF No. 86-1 at 15. The Circuit also

made this clear in Alta Wind. 897 F.3d at 1376. Specifically, the Transaction was an “applicable

asset acquisition” under I.R.C. § 1060 because the MIPSA and EPC Agreements transferred

assets (i.e., the Facility’s tangible assets, the PPAs, and the LGIA) that constitute a “trade or

business” whose “character is such that goodwill or going concern value could under any

circumstances attach to such group.” 26 C.F.R. § 1.1060-1(b)(2)(i)(B).

15

Two of the three non-exhaustive factors identifying goodwill and going concern value

support this conclusion. See 26 C.F.R. § 1.1060-1(b)(2)(iii). First is the presence of intangible

assets. 26 C.F.R. § 1.1060-1(b)(2)(iii)(A). The PPAs and the LGIA are intangible assets, as

discussed below. See infra III.B.; see also Alta Wind, 897 F.3d at 1373-74 (recognizing that at

least some portion of the PPAs and the interconnection agreement are intangible assets). Second

is the presence of related transactions. 26 C.F.R. § 1.1060-1(b)(2)(iii)(C). Here, the O&M

Agreements are related transactions between the purchaser (NextEra and GE) and seller (First

Solar) in connection with the transferred assets via the EPC Agreements and the MIPSA because

the O&M Agreements provide for operations and maintenance services to the Facility by First

Solar. See ECF Nos. 81-16, 81-17, & 81-18; see also Alta Wind, 897 F.3d at 1373 (finding that

leaseback agreements for the seller to operate the assets are related transactions).

The fact that the Facility was not yet operational at the time of the Transaction makes no

difference. See Alta Wind, 897 F.3d at 1373 (citing 26 C.F.R. § 1.1060-1(b)(2)(iii)) (“There is

no need to show that a transaction had actual, accrued goodwill or going concern value at the

time of the transaction.”). That is particularly true here given the Parties’ expected ROE from

the Facility as reflected in the “Project Model” that formed the basis of the EPC Agreement and

MIPSA negotiated prices. See ECF No. 81-10 at App’x 351-53; see also ECF No. 81-25

(Project Model Cover Sheet) and related CD (Project Model); Alta Wind, 897 F.3d at 1373, 1375

(finding that goodwill could attach to assets yet to be in operation that were negotiated based on

anticipated cash flows that were valued with reference to intangible assets such as PPAs).

Accordingly, because the Desert Sunlight Transaction is an applicable asset acquisition, the

I.R.C. § 1060 allocation applies in this case.

2. Plaintiffs’ I.R.C. § 1060 Allocation.

Given I.R.C. § 1060’s application to this case, the Government moves for summary

judgment on the ground that Plaintiffs have not provided the required I.R.C. § 1060 allocation of

the purchase price of the Desert Sunlight Transaction in accordance with the fair market value of

the assets acquired. ECF No. 80 at 28-29, 32, 36-37. The Government primarily focuses on the

fact that Plaintiffs did not complete an IRS Form 8594 for their I.R.C. § 1060 allocation, and that

their failure to do so precludes their eligibility for a further Section 1603 grant. Id. at 32; ECF

No. 91 at 35. The Court disagrees.

a) Plaintiffs’ failure to submit an IRS Form 8594 is not fatal to their

claim.

The contention that IRS Form 8594 is the sole method to submit an I.R.C. § 1060

allocation for Section 1603 purposes is without merit. The Government has cited no authority to

support this proposition, and the Government itself has even implied that an I.R.C. § 1060

allocation could take other forms than Form 8594. According to the Government, “plaintiffs

have not presented a copy of a filed Form 8594, or otherwise provided the government with the

required allocation of the purchase price in the Desert Sunlight Transaction in accordance with

the fair market value of the assets acquired.” ECF No. 80 at 32 (emphasis added). Indeed, it is

particularly difficult to accept that IRS Form 8594 is the only way to provide an I.R.C. § 1060

allocation given the limited information it requires. The Form merely contains boxes to fill in:

(1) each asset class’s aggregate fair market value; (2) each asset class’s allocation of the sales

16

price; (3) the assets’ total aggregate fair market value; and (4) the assets’ total allocation of the

sales price. See ECF No. 81-32 at App’x 2841-42. Should an applicant for a Section 1603 grant

provide the same or more detailed information as its I.R.C. § 1060 allocation, the Government

has offered no reason why it should be rejected for failing to use IRS Form 8594. Indeed, the

penalty for failing to submit a Form 8594 is $250, not forfeiture of a claim. See 26 U.S.C. §§

6721(a)(1), 6724(d)(1)(B)(xvii).

It is also difficult to accept the Government’s argument that it cannot determine whether

Plaintiffs were entitled to any Section 1603 grant, much less the amount they seek in this action,

because they did not submit an IRS Form 8594. ECF No. 80 at 32. If it truly thought Plaintiffs’

Section 1603 applications were fatally deficient, it is unfathomable that the Government would

have approved and paid more than $555 million of Plaintiffs’ grant requests already. The

Government conducts an extensive review of each Section 1603 application before approving

them. See ECF No. 88 at App’x 249-51. Therefore, the Government’s approving most of

Plaintiffs’ applications suggests that the Government was, and presumably is, able to determine

Plaintiffs’ Section 1603 eligibility.

During oral argument, the Government attempted to reconcile this contradiction,

explaining that, under Section 1603, “the idea was to get this money out quick because the

financing for alternative energy products -- projects was drying up” and “Treasury, you know,

had to use different rubrics to determine which cases they were going to pay more attention to

and which cases they weren’t, [asking] . . . are we comfortable enough making some sort of

payment in the neighborhood without actually making the taxpayer go through the allocation that

is needed to be done?” ECF No. 106 at 17:21-23, 17:25-18:2, 18:6-9.

But it appears that there was back-and-forth between the Government and Plaintiffs in

which the Government had the opportunity to, and did, seek additional information from

Plaintiffs while it was considering their Section 1603 applications. See ECF No. 81-28

(Plaintiffs’ responses to Government questions and requests for additional documentation). The

Government’s requests included: “We are unable to find this [document] . . . please provide

another copy”; “Please provide the following original Excel financial models”; and “Using best

efforts, please provide a current estimate and cost segregation of the expected total cost of the

entire Desert Sunlight project . . . [and] an excel version of the September 20, 2011, Cost

Breakdown Study prepared by KPMG.” Id. at App’x 2637-38. Notably missing from the

Government’s requests for additional information is any request for a completed IRS Form 8594,

which indicates the Government did not need that form to determine Plaintiffs’ eligibility for a

Section 1603 grant. Nor does the Court.

The cases the Government relies upon do not hold to the contrary. As an initial matter,

nobody disputes that the Plaintiffs bear the burden of proof to show that they are entitled to an

additional § 1603 payment. ECF 80 at 28 (citing W.E. Partners II, LLC v. United States, 119

Fed. Cl. 684, 690 (2015); WestRock Va. Corp., 136 Fed. Cl. at 284); see also ECF No. 87 at 32

(Plaintiffs acknowledging what they must show). The Government also relies heavily on

WestRock for the proposition that “[i]f plaintiffs fail to put forward sufficient evidence of an

appropriate allocation of the overall purchase price for the Desert Sunlight enterprise as between

eligible and ineligible property that would demonstrate entitlement to an additional § 1603

entitlement, then plaintiffs should not recover any additional payment.” ECF No. 80 at 28 (citing

17

WestRock Va. Corp., 136 Fed. Cl. at 283-84) (emphasis in original). True enough, but the

Government attempts to stretch this proposition to support summary judgment because

“plaintiffs have not presented a copy of a filed Form 8594, or otherwise provided the government

with the required allocation of the purchase price in the Desert Sunlight Transaction in

accordance with the fair market value of the assets acquired.” ECF No. 80 at 32. Whether

Plaintiffs provided a sufficient § 1060 allocation is a factual matter for trial.

b) A genuine dispute of material fact exists whether Plaintiffs

provided a sufficient I.R.C. § 1060 allocation.

Summary judgment is not appropriate here because there are disputed material facts

regarding whether Plaintiffs provided a sufficient I.R.C. § 1060 allocation. Plaintiffs contend

that they provided a proper and sufficient allocation in the cost segregations and Total Cost

Spreadsheet they submitted to Treasury with their Section 1603 applications. E.g., ECF No. 86-

1 at 63-64. The Government argues that Plaintiffs’ cost segregations and Total Cost Spreadsheet

are not a proper I.R.C. § 1060 allocation. ECF No. 91 at 7. The Government also argues that

Plaintiffs have failed to otherwise produce evidence regarding the fair market value of the assets,

which dooms their claim. Id. at 13-14, 18-21. The Court disagrees. The Government’s

argument that Plaintiffs failed to produce any evidence of the fair market value of the Facility

ignores all the evidence that Plaintiffs produced on that very point. Indeed, the Government

spends nearly a dozen pages explaining why various pieces of Plaintiffs’ evidence of the

Facility’s fair market value are insufficient, standing alone, to establish the fair market value.

ECF No. 80 at 32-37; ECF No. 91 at 13-14, 18-21. But there is no requirement that the Court

view each piece of information in isolation. And Plaintiffs have clearly provided enough

information to create a factual dispute as to the fair market value of the Facility.

(1) The Government’s argument regarding Class III assets

fails.

The Government points to the financing agreements as showing that Plaintiffs did not

provide a sufficient I.R.C. §1060 allocation. Specifically, the financing agreements that the

Plaintiffs secured from private banks are Class III assets, according to the Government, yet the

Plaintiffs never valued or allocated any portion of the consideration to these assets. ECF No. 91

at 8-9. The Government is mistaken, however, for at least two reasons.

First, I.R.C. § 1060 allocates only the consideration for assets acquired in a transaction.

I.R.C. § 1060(a)(2) (providing that “the consideration received for such assets shall be allocated

among such assets acquired in such acquisition”) (emphasis added). Plaintiffs, however, did not

acquire the loan agreements from First Solar in the Desert Sunlight Transaction. Rather,

Plaintiffs executed them separately with private financial institutions. ECF No. 95 at 5.

Plaintiffs executed the “A-2 Loan Agreement” with the U.S. Department of Energy and

Deutsche Bank on September 29, 2011, contemporaneously with the Transaction. See ECF No.

91-5. First Solar is not party to it to this agreement. The same is true of the other financing

agreements. See Scarff Decl. ¶ 3 (ECF No. 95-2 at App’x 2866). Therefore, the Transaction’s

consideration is not allocated to the loan agreements under I.R.C. § 1060.

18

Second, even if Plaintiffs acquired the agreements in the Transaction, the fact is that they

are not assets. Rather, they are liabilities reflecting amounts owed to private banks. I.R.C. §

1060, however, only allocates the consideration for assets acquired in a transaction. See I.R.C. §

1060(a) (providing that “the consideration received for such assets shall be allocated among such

assets acquired in such acquisition in the same manner as amounts are allocated to assets under

section 338(b)(5).”) (emphasis added). Indeed, Class III property is specifically referred to as

assets. See 26 C.F.R. § 1.338-6(b)(2)(iii) (“Class III assets. Class III assets are assets . . . .”)

(emphasis added). Thus, the financing agreements are not included in the Desert Sunlight

Transaction for allocation under I.R.C. § 1060 as Class III assets or otherwise, and evidence of

their fair market value is unnecessary for the requisite I.R.C. § 1060 allocation for Plaintiffs’

sought Section 1603 relief.

The Government also argues that Plaintiffs failed to provide a sufficient I.R.C. § 1060

allocation because they have not valued or allocated consideration to another purported Class III

asset: the financing-related agreements First Solar entered with private banks. ECF No. 91 at 8-

9. But the regulations defining Class III assets as including “debt instruments” does not define

that term. 26 C.F.R. § 1.338-6(b)(2)(iii)(A). While undefined in the regulation, a Class III “debt

instrument” appears to mean an instrument under which a debt is owed because the Code defines

a “debt instrument” as “a bond, debenture, note, or certificate or other evidence of indebtedness.”

I.R.C. § 1275(a)(1)(A) (emphasis added). But neither First Solar nor Plaintiffs owe any debts

under First Solar’s financing-related agreements. Instead, one of these documents is a 2009

letter from Goldman Sachs to First Solar confirming that Goldman would serve as the structuring

agent for future financing agreements. ECF No. 91-4. The Government also points to ECF No.

91-3 as a Class III debt instrument, but that document is merely an engagement letter between

First Solar, Desert Sunlight, Goldman, and Citigroup under which Goldman and Citigroup would

serve as “joint lead arrangers and joint bookmakers,” and provide “structuring assistance” for

future financing. Id. at App’x 4341, 4343. Finally, the Government points to a conditional loan

commitment letter between Citibank and First Solar in which Citibank offered to provide

financing if certain conditions precedent were met. ECF No. 95-2 at App’x 2892-96. Among

the conditions precedent is “the preparation, execution and delivery of mutually acceptable

Credit Documents,” First Solar’s provision of all “know your customer” documents, and

Citibank’s verification of the information received. See id. at App’x 2893. Here too, there is

nothing in this document creating an obligation or indebtedness. Therefore, First Solar’s

financing-related agreements are not debt instruments and thus not Class III assets for purposes

of Plaintiffs’ I.R.C. § 1060 allocation.

This comports with the apparent understanding the parties, including the Government,

had of liabilities in the Alta Wind litigation. In Alta Wind, the parties stipulated that one of the

transactions involved the purchaser’s assumption of $307,147,911.69 of liabilities from the

seller. Stipulation of Facts ¶ 22, Alta Wind I Owner Lessor C v. United States, No. 13-402 (Fed.

Cl. Apr. 15, 2016) (ECF No. 115). Yet, when Alta Wind was on appeal before the Federal

Circuit, “the parties agree[d] that none of the assets at issue in this case fits within Class I, II, III,

or IV.” 897 F.3d at 1376. While there may be distinctions between those liabilities and the ones

before this Court, it does not appear that the common understanding of Class III assets includes

assumed liabilities (assuming, counterfactually, that the financing agreements were acquired

through the Transaction).

19

As an alternative, the Government argues that if the financing agreements are not Class

III assets, the agreements are intangible assets for which Plaintiffs paid First Solar under the

MIPSA. ECF No. 106 at 37:10-16, 39:11-25. Further, the Government argues that, if not Class

III assets, the agreements have no asset class to fall under except Class V. Id. at 37:23-38:1,

39:15-25. Asserting that Plaintiffs did not value the agreements, the Government argues that

Plaintiffs’ I.R.C. § 1060 allocation fails. Id. at 37:23-38:1. The Court disagrees. First Solar’s

financing-related agreements are intangible assets, they are not Class V assets but rather

supplier-based intangible assets under I.R.C. § 197 (“Section 197”), and Section 197 assets fall

under Class VI. 26 C.F.R. § 1.338-6(b)(2)(vi). “A supplier-based intangible is the value

resulting from the future acquisition, pursuant to contractual or other relationships with suppliers

in the ordinary course of business, of goods or services that will be sold or used by the taxpayer.”

26 C.F.R. § 1.197-2(b)(7)(i). First Solar’s financing-related agreements are supplier-based

intangible assets because they form a contractual relationship with private banks in the ordinary

course of business regarding potential future loans. See also I.R.S. Tech. Adv. Mem. 199909002

(March 5, 1999) (concluding that an agreement under which a taxpayer pays a fee for the

subsequent sale of customer notes to company is a supplier-based Section 197 intangible asset).

As discussed below, Class VI assets need not be valued to perform the requisite I.R.C. § 1060

allocation unless there is a portion of the transaction price remaining unallocated after allocation

to Classes I-V. See infra III.B.3. Thus, even if Plaintiffs did not value First Solar’s financing-

related agreements, that would not affect Plaintiffs’ I.R.C. § 1060 allocation if Plaintiff is correct

that the entire Transaction price is allocated to Class V assets.

Accordingly, the Transaction had no Class III assets to which any of the Transaction’s

consideration had to be allocated under I.R.C. § 1060.

(2) A genuine dispute of material fact exists whether the cost

segregations and total cost spreadsheet contain the Class V assets’

fair market values.

Whether Plaintiffs provided a sufficient I.R.C. § 1060 allocation hinges on whether they

submitted the fair market values of the Class V assets to Treasury. Here, there is a genuine

dispute of material fact because Plaintiffs submitted detailed cost segregations to Treasury with

their Section 1603 applications, which they claim contain the fair market values of the Class V

assets. Whether these prices are, in fact, the fair market prices “is a question of pure fact . . . .”

Pabst Brewing Co. v. Comm’r, 69 T.C.M. (CCH) 2773 (1995), 1995 WL 325875, at *22.

Courts have long recognized that “[f]air market value is the price at which property

would change hands between a willing buyer and a willing seller, neither being under any

compulsion to buy or sell, and both reasonably informed as to all relevant facts.” Solitron

Devices, Inc. v. Comm’r, 80 T.C. 1, 20-21 (1983), aff’d 744 F.2d 95 (11th Cir. 1984); see also,

e.g., Innovair Aviation, Ltd. v. United States, 83 Fed. Cl. 498, 501 (2008) (“The Supreme Court

has held that fair market value is the amount that ‘a willing and informed buyer . . . under no

compulsion to buy, will pay, and what a willing and informed seller, under no compulsion to sell,

will accept.’”) (emphasis omitted) (citation omitted); United States v. Cartwright, 411 U.S. 546,

551 (1973) (“The willing buyer-willing seller test of fair market value is nearly as old as the

federal income, estate, and gifts taxes themselves[.]”). Courts generally accept that in “a sale

between unrelated parties at arm’s length[,] . . . the sales price is the best evidence of fair market

20

value.” Solitron Devices, 80 T.C. at 20; see also, e.g., Suitum v. Tahoe Reg’l Plan. Agency, 520

U.S. 725, 741-42 (1997) (recognizing the benefit of arm’s length prices in determining market

value); Schonfeld v. Hilliard, 218 F.3d 164, 178 (2d Cir. 2000) (“[I]t is well-established that a

recent sale price for the subject asset, negotiated by parties at arm’s length, is the ‘best evidence’

of its market value.”) (citations omitted). Thus, Plaintiffs contend that the actual amounts they

paid for each asset conveyed in the Transaction are the fair market values for each of those

assets.

The Government does not dispute that the willing-buyer, willing-seller standard

determines fair market value, but it contends that the standard has a particular meaning. Namely,

the Government maintains that “this standard requires an analysis of the property from the

perspective of a hypothetical buyer and a hypothetical seller, not the actual parties to the

transaction.” ECF No. 91 at 13 (emphasis added and emphasis removed). There are several

issues with this argument.

First, the Government questions the applicability of Plaintiffs’ cases to the present case

because they supposedly do not involve an “applicable asset acquisition” under I.R.C. § 1060.

Id. at 14. Even assuming that is a meaningful distinction, however, there are cases supporting

this standard that involve applicable asset acquisitions. See., e.g., East Ford, Inc. v. Comm’r, 67

T.C.M. (CCH) 3068 (1994), 1994 WL 243713, at *3-4 (finding that the sale of a truck-leasing

business was an “applicable asset acquisition” under I.R.C. § 1060). In fact, East Ford

undermines the Government’s argument because there the Court had to determine the reasonable

values of the assets because the two parties to the applicable asset transaction assigned different

values to the same assets to maximize their respective tax treatment. According to the Tax

Court: “Although the parties could have avoided this dispute by agreeing at the time of the sale

to a reasonable allocation of the purchase price, their failure to do so leaves it to this Court to

assign reasonable values to the assets transferred.” Id. at *1. If the parties could have avoided

the dispute by assigning reasonable values to assets at the time of their transfer, the Government

cannot be correct that the actual transaction is not sufficient to overcome summary judgment.

Second, Treasury itself reviews Section 1603 grant applications under the willing buyer –

willing seller paradigm. According to its 2011 guidance, “[t]he IRS generally defines fair market

value . . . as ‘the price at which property would change hands between a buyer and a seller,

neither having to buy or sell, and both having reasonable knowledge of all necessary facts.’”

ECF No. 88 at App’x 251. In reviewing Section 1603 grant applications, moreover, Treasury

assumes that “a Section 1603 applicant’s claimed cost basis reflects the eligible property’s fair

market value,” so long as the property was purchased through an arm’s-length transaction

involving no unusual circumstances. Id. at App’x 249. “Once a plaintiff has produced such

evidence, the burden is on the defendant to demonstrate ‘special circumstances which would

negate [the relevance] of a prior arm’s-length purchase price.’” Schonfeld, 218 F.3d at 179

(citation omitted). Even if the Government had come forward with evidence that the Transaction

was not arm’s length or that there was compulsion to buy or sell, those would be issues for trial,

not summary judgment.

Third, the cases that the Government relies upon to assert that the actual sales price does

not reflect the Plaintiffs’ basis do not help the Government here. For example, in Estate of

Bright v. United States, the court interpreted the estate tax regulation, which provides that “[t]he

21

fair market value is the price at which the property would change hands between a willing buyer

and a willing seller, neither being under any compulsion to buy or to sell and both having

reasonable knowledge of relevant facts.” 658 F.2d 999, 1005 (5th Cir. 1981) (en banc) (citing 26

C.F.R. § 20.2031-1(b)). In doing so, the court commented that “[i]t is apparent from the

language of the regulation that the ‘willing seller’ is not the estate itself, but is a hypothetical

seller.” Id. The Government also relies on Pabst Brewing Company v. Commissioner, as

holding that the willing buyer – willing seller “standard requires the court ‘to analyze the

property from the perspective of a hypothetical buyer and a hypothetical seller; not the actual

parties to the transaction.’” ECF No. 91 at 22-23 (citing Pabst, 69 T.C.M. (CCH) 2773, 1995

WL 325875, at *22). The Government maintains that it is “[c]ontrary to the hypothetical buyer

and seller standard of fair market valuation [for] plaintiffs [to] rely on the purchase price to

which they—the actual parties to the transaction—agreed to attempt to establish fair market

value.” ECF No. 91 at 13. According to the Government, “[t]he Transaction purchase price is

only probative of how the parties agreed to divvy up the total consideration for the purchase and

sale of a going concern business enterprise between the MIPSA and EPC Agreements,” and that

“[n]o inference may be drawn that the prices ascribed in these agreements by themselves are

indicative of the fair market value of the tangible solar property.” Id. “Thus,” the Government

maintains, “plaintiffs’ reliance on their own purchase price as evidence of fair market value is

insufficient to overcome summary judgment in favor of the government.” Id. at 14. The Court

disagrees.

To the extent the cases the Government relies upon deal with transfers of assets upon the

death of the owner without an actual transaction, they do not help the Government here. It goes

without saying that when there was no arms-length transaction, the Court must resort to a

hypothetical buyer and seller. As the court stated in Bank of California, National Ass’n v.

Commissioner, “we are required to assume the existence of a willing buyer and a willing seller,

regardless of whether they actually existed or not, and to assume that the property could and

would change hands, even though such a change could not in fact occur.” 133 F.2d 428, 433

(9th Cir. 1943) (emphasis added). In fact, the emphasis on the hypothetical willing buyer and

seller in such cases is not intended to the exclusion of an actual transaction—which, again, did

not occur—but instead to the exclusion of the decedent’s interests before death or the estate’s

interests after death. As the court in Estate of Bright explained:

The notion of the “willing seller” as being hypothetical is also

supported by the theory that the estate tax is an excise tax on the

transfer of property at death and accordingly that the valuation is to

be made as of the moment of death and is to be measured by the

interest that passes, as contrasted with the interest held by the

decedent before death or the interest held by the legatee after

death.

658 F.2d at 1006 (emphasis added). Stated differently:

Defining fair market value with reference to hypothetical willing-

buyers and willing-sellers provides an objective standard by which

to measure value. . . . The use of an objective standard avoids the

22

uncertainties that would otherwise be inherent if valuation methods

attempted to account for the likelihood that estates, legatees, or

heirs would sell their interests together with others who hold

undivided interests in the property. Executors will not have to

make delicate inquiries into the feelings, attitudes, and anticipated

behavior of those holding undivided interests in the property . . . .

Propstra v. United States, 680 F.2d 1248, 1252 (9th Cir. 1982) (citations omitted). Accordingly,

Estate of Bright and similar estate tax dispute cases do not support minimizing the import of the

price at which an actual buyer and seller transferred property at apparent arm’s length in favor of

evidence of what a hypothetical buyer and seller would rather do to value such property.

The same is true for Whitehouse Hotel Limited Partnership v. Commissioner of Internal

Revenue, 615 F.3d 321 (5th Cir. 2010). See ECF No. 106 at 111:9-11. As an initial observation,

Whitehouse deals with the tax implications of the granting of a historic preservation easement to

a nonprofit entity that was treated as a charitable contribution for tax purposes. 615 F.3d at 325-

26. As with the estate cases, there was no arm’s length transaction at all, requiring the parties

and the court to examine (1) the “comparable-sales” method of valuating real property, which

looks to the ‘“sales from a willing seller to a willing buyer of similar property in the vicinity at or

about the same time’ as the property being valued[,]”; and (2) the inquiry of “what a hypothetical

willing buyer would consider in deciding how much to pay for the property[]” in determining

fair market value. Id. at 333, 335. Like in Estate of Bright, the court in Whitehouse had no

choice but to think in hypothetical terms because there was no actual buyer and seller in that

case. Therefore, Whitehouse also does not suggest overlooking the price at which an actual

buyer and seller transferred property at arm’s length, as the Government posits.

As for the Government’s reliance on Pabst, a non-estate tax case, the Government

overstates that case’s significance. Pabst involved a transaction between companies in which

various assets were priced and transferred between the parties. 69 T.C.M. (CCH) 2773 (1995),

1995 WL 32587, at *8-9. In relevant part, one of the issues before the court concerned the

proper valuation of the transferred assets. Id. at *19. The petitioner moved for partial summary

judgment that the fair market value of the transferred assets was the amount at which they were

priced because the transfer was at arm’s length. Id. The court denied the petitioner’s partial

summary judgment motion because the question of fair market value “is a question of pure

fact . . . .” Id. at *22. And while the Court does state that its analysis requires the hypothetical

seller and buyer, it did so because the Government “raises a genuine issue of material fact as to

the arm’s-length nature of the transaction and the fair market value of the Transferred Assets.”

Id. at *24. Accordingly, Pabst does not support the Government’s proposition that an actual

transaction’s purchase price is necessarily insufficient, and that further evidence must be shown

in valuing assets under the hypothetical willing-buyer, willing-seller standard. Rather, Pabst (at

most) suggests that the purchase price should not be the sole evidence consulted in valuing assets

and that the price could potentially be as important as other evidence in determining assets’ fair

market value.

The Government further argues that adopting the non-hypothetical willing-buyer, willing-

seller standard “would render § 1060 nugatory because § 1060 was enacted to ensure that buyers

and sellers of assets constituting a trade or business did not manipulate tax laws to their own

23

benefit.” ECF No. 91 at 14. According to the Government, “[i]f plaintiffs could rely on their

own agreement as substantive evidence of the fair market value of the assets conveyed in an

applicable asset acquisition, the ability of the government to challenge an erroneous allocation

and insist on compliance with the tax laws would be severely hampered.” Id. Not so. The

Government is free to challenge the Plaintiffs’ valuation of the Transaction assets and whether

the Transaction was truly negotiated at arm’s length. That does not mean that the Plaintiffs

cannot meet their burden for summary judgment based largely on their own allocation of prices.

In short, the hypothetical buyer and seller reflect that the Government and the Court are not

bound by the Plaintiffs’ allocation of assets, not that their allocation is irrelevant.

And Plaintiffs have come forward with evidence that, if true, would show that the

Transaction qualifies as an arms-length transaction such that their assets’ prices are indicative of

their fair market values. Specifically, there is no indication that NextEra or GE were under any

compulsion to buy the Facility. It also does not appear that First Solar was under any

compulsion to sell the Facility. At oral argument, the Government briefly argued that First Solar

was compelled to agree to the MIPSA’s terms because it otherwise would lose out on signing the

EPC Agreements. ECF No. 106 at 97:18-21. Even if true, this is an issue for trial and not

summary judgment.

Plaintiffs’ evidence also suggests that First Solar, NextEra, and GE were fully

knowledgeable about the Transaction given their respective experience in the renewable energy

industry. First Solar describes itself as the world’s leading manufacturer of solar PV facility

“thin film” solar modules, and is a leader in developing, financing, engineering, constructing,

operating, and selling many of the world’s largest grid-connected solar PV power plants.

Brannen Decl. ¶ 15; see also ECF No. 81-2 at App’x 26. NextEra builds and operates solar

power facilities and has been significantly involved in the solar industry since 2009. Id. ¶ 7.

And GE is a financial services provider, ECF No. 81-4 at App’x 88, with substantial experience

investing in the renewable energy industry, Brannen Decl. ¶ 13. Mr. Draper testified that GE and

NextEra “were . . . extremely well-versed in . . . the issues that we were dealing with, both on the

technical side and risk allocation under EPC agreements . . . .” Draper Dep. Tr. 266:24-267:5.

In addition, the Project Model further supports that First Solar, NextEra, and GE were well-

informed about the Desert Sunlight Transaction, as shown by the intricate formulas used to

calculate the Transaction’s prices based on the Facility’s expected ROE. See ECF No. 81-10 at

App’x 351-53.

Plaintiffs also assert that the negotiations over the EPC Agreements demonstrate that this

was an arm’s length transaction. NextEra and GE negotiated down the total EPC Agreement

price by over $400 million from First Solar’s initial offering of over $2.36 billion to the final

price of $1,950,807,086. Brannen Decl. ¶ 22; Draper Dep. Tr. at 264:21-12. NextEra and GE

also convinced First Solar to take on greater risk than they originally proposed, even with a

lower total EPC Agreement price, as a result of “the hard bargain that NextEra and GE drove.”

Brannen Decl. ¶ 23; Draper Dep. Tr. at 270:25-271:19, 273:1-7, 274:10-15, 274:22-275:6.

Indeed, Mr. Draper testified that “it was very arm’s length . . . it was an extremely hard

negotiation with GE and NextEra . . . .” Draper Dep. Tr. at 265:13-17.

Moreover, each party had reason to negotiate fair market value EPC Agreements. Mr.

Brannen explains that he had multiple reasons to do so beyond pursuing NextEra’s normal

24

business objective of paying only fair market value for EPC agreements. Brannen Decl. ¶ 24.

First, Mr. Brannen states he knew that NextEra would require loans to pay for the EPC

Agreements, and that banks would not finance the Agreements if they were above market. Id.

Second, due in part to the magnitude of the Facility’s construction, Mr. Brannen states he feared

that First Solar may not complete the Project, and that NextEra did not want to have paid First

Solar an above-market amount for any work already completed. Id. Third, Mr. Brannen states

that he had a personal incentive to reach the best price and lowest risk EPC agreements because a

significant portion of his salary was an incentive payment tied to the deal reached. Id. ¶ 25. Mr.

Draper similarly testified that First Solar was “trying to stay cash neutral or cash positive

throughout the course of construction for the project.” Draper Dep. Tr. at 252:10-12 (ECF No.

81-63 at App’x 4205). In addition to these indicia of arm’s length, Shaw concluded that the EPC

Agreement prices were comparable to prices in third-party, arm’s length transactions, meaning

that First Solar being the seller and construction contractor did not distort the prices in Shaw’s

opinion. ECF No. 88-1 at App’x 2576; Walker Dep. Tr. 92:4-94:18.

As a result, there is a genuine dispute of material fact whether the Transaction’s asset

prices as contained in the cost segregations and the Total Cost Spreadsheet—and as further

detailed by Exhibit I to the EPC Agreements—amount to their fair market values.

(3) There is a dispute of material fact regarding the fair market

value of the MIPSA assets.

The Government also argues that Plaintiffs have not provided evidence of the MIPSA

assets’ fair market value based on their prices alone because of the disparity between the

approximately $35 million First Solar spent to develop the assets and the far lower price of just

over $14 million that Plaintiffs paid under the MIPSA. ECF No. 91 at 11-12. At trial, the

Government may be proven correct. But this is a pure question of fact not amenable to

resolution on summary judgment because there remains a genuine dispute of material fact

whether the MIPSA assets’ purchase prices reflect their fair market value. The fact that the

MIPSA contract price is far lower than the amount First Solar spent developing its assets does

not mean that the price is not the fair market value. It is certainly possible for things to sell for

less than the cost of producing them, and a seller is willing to accept less than its cost to produce

the items for a number of reasons (e.g., to avoid further costs and “cut its losses”). Therefore,

the prices for the Desert Sunlight Transaction’s assets could indicate their fair market value, and

there is thus a genuine dispute of material fact whether the cost segregations and Total Cost

Spreadsheet containing the prices suffice to serve as Plaintiffs’ required I.R.C. § 1060 allocation.

(4) Plaintiffs Rely on More than just the Transaction Price to

Show the Assets’ Fair Market Value.

In addition to the evidence regarding the Transaction negotiations, Plaintiffs also rely on

several analyses of the Project and other benchmarks to support their contention that the

Transaction price allocations represent the fair market values of the Transaction assets. Taken

together, these analyses further bolster the conclusion that there is a genuine dispute of material

facts—making summary judgment inappropriate.

25

Several firms with significant experience in the construction of power generation

facilities found that the Transaction price was reasonable. Shaw determined that First Solar’s

proposed total EPC Agreement price reflected a fair market value. ECF No. 88-1 at App’x 2576.

Burns and Roe similarly found that the proposed EPC Agreement price was reasonable. Walker

Dep. Tr. at 53:16-22, 58:16-59:18. Luminate also concluded that both First Solar’s initially

proposed total EPC Agreement price and the final total EPC Agreement price were reasonable.

Glover Dep. Tr. at 17:20-18:7, 79:20-81:18 (ECF No. 81-36 at App’x 3181-82, 3197). And

Black & Veatch concluded that the final total EPC Agreement price was “consistent with the

total construction cost of other PV solar generating facilities utilizing the same technology and

with our understanding of current market pricing in the solar PV industry.” ECF No. 88 at

App’x 258.

In addition to the independent engineering firms, the SETP/NREL concluded that the

originally proposed total Project price was “below the current estimated average total project

cost for comparable projects and [is] within a reasonable range of the expected system

price . . . .” ECF No. 88-1 at App’x 2425; see also, id. at App’x 2420 (an earlier SETP/NREL

memorandum concluding that “[b]ased on this analysis the EPC price falls within an acceptable

range of expected system costs based on technology selection, system size and configuration.”).

The SETP/NREL specifically determined that the projected EPC price of $3.43/Wdc was within

a reasonable range of NREL’s estimated EPC system price for a facility like the Desert Sunlight

Facility of $2.93/Wdc. Id. at App’x 2427-28. Further, Dr. Ramesh stated in his memorandum

that “[w]e have compared a detailed break out of the pricing for the elements of the EPC contract

against our model and have found the pricing to be within our expected range.” Id. at App’x

2426.

Plaintiffs also point to other valuations and benchmarks as further evidence of the EPC

Agreement assets’ fair market values. For one, NextEra made its own determination that the

final total EPC Agreement price was fair market value via its “cost build up,” which was

reviewed by BEW. Brannen Decl. ¶ 26e. In addition, DOE conducted its own due diligence and

determined that there was a reasonable assumption that, based on the originally proposed total

EPC Agreement price, the loan would be repaid by comparing the proposed total EPC

Agreement price to other projects in its internal databases. Walker Dep. Tr. at 99:8-100:12.

Moreover, all estimated total EPC Agreement prices were below Treasury’s 2011 first quarter

benchmark of fair market value for large commercial solar PV, which was $4/W. Brannen Decl.

¶ 26d; ECF No. 88 at App’x 249-50. All the estimated total EPC Agreement prices were

similarly less than publicly reported estimates of EPC agreement prices of utility-scale solar PV

facilities, including SEIA’s estimate of $3.85/Wdc, ECF No. 88 at App’x 222, and NREL’s

approximate estimate of $4/Wdc, Id. at App’x 239. Further, Mr. Brannen’s estimated total EPC

Agreement price of $2.69/Wdc for the originally planned 724 MWdc-capacity Facility, Brannen

Decl. ¶ 21, fell below the $2.80/Wdc or $2.92/Wdc prices that Treasury indicated at the time

were comparable EPC agreement prices. Walker Dep. Tr. at 157:13-158:3. And Deloitte

verified that Plaintiffs’ Section 1603 applications were “fairly stated, in all material respects.”

Pitale Decl. ¶¶ 41-42.

In addition to the above evidence from the events culminating in the Desert Sunlight

Transaction, Plaintiffs cite two additional pieces of evidence of the EPC Agreement assets’ fair

market values.

26

First, Plaintiffs cite an April 2013 report from the U.S. Energy Information

Administration (“EIA”), entitled “Updated Capital Cost Estimates for Utility Scale Electricity

Generating Plants.” ECF No. 86-1 at 51-52; ECF No. 88-1 at App’x 2588-2604. The purpose of

the report in part was to provide information on the EPC costs of various types of utility-scale

power facilities in 2012 dollars. ECF No. 88-1 at App’x 2593-94, 2628. Its authors cautioned,

however, that all estimates in the report were “broad in scope” and “a more in-depth cost

assessment would require a more detailed level of engineering and design work, tailored to a

specific site.” Id. at App’x 2594. One of the facilities studied was a 150 MWac solar PV facility,

id., for which the report indicates that the facility’s total EPC costs would be approximately

$3.49 per kilowatt (“/kW”) (excluding owner costs), id. at App’x 2622, 2730. And this report

concluded that in California, the cost would be substantially higher. Id. at App’x 2784. Based

on a typical ratio of DC module capacity to AC inverter capacity being 1.3:1, id. at App’x 2727-

28, the generic cost would be $2.68/Wdc, Spence Decl. at 155:4-156:15 (ECF No. 88-1 at App’x

2583). And the lowest cost in California would be $2.88/Wdc. Id. at 165:19-166:8.

Accordingly, Mr. Brannen’s estimated Desert Sunlight EPC Agreement price of either

$2.63/Wdc or $2.73/Wdc, Brannen Decl. ¶ 21, was less than the lowest EPC price estimate in the

EIA report. ECF No. 87 at 51-52; ECF No. 88-1 at App’x 2588-2604.

Second, Plaintiffs rely on the opinion of Mr. Robert Charles. ECF No. 87 at 54-57. Mr.

Charles is an independent engineer Plaintiffs retained as an expert witness who states that “the

price that plaintiffs paid First Solar under the EPC contracts was a fair market value price to

engineer, procure and construct the Desert Sunlight Facility’s physical assets.” Charles Decl. ¶

7. Mr. Charles “reached that conclusion based on a comparison of the Desert Sunlight EPC price

with the prices of other contemporaneous EPC contracts for utility-scale solar PV facilities

employing exactly the same solar technology as Desert Sunlight.” Id. According to Mr. Charles,

“[i]ndependent engineers like me regard this market comparables approach as the best way to

conduct an independent assessment of whether an EPC price reflects fair market value when

appropriate comparables are available, as they were here.” Id. In addition, Mr. Charles

evaluated the solar module prices specifically, which he maintains are the most important and

costly component of a solar PV facility. Id. ¶¶ 11, 16. He concluded they were priced at fair

market value as well. Id. ¶ 11.

In response to the evidence of the EPC Agreement assets’ fair market values that

Plaintiffs muster, the Government raises several arguments why, actually, “none of

[it] . . . establishes the fair market value of tangible solar property.” ECF No. 91 at 18.

Specifically, the Government contends that the SETP/NREL, Luminate, and Shaw

determinations that the EPC Agreement prices fall within a certain price range is different from

determining their assets’ fair market value. See ECF No. 80 at 33-34. The Government also

asserts that Luminate’s finding of a price’s reasonableness is not equivalent to its fair market

value. Id. at 33 (citation omitted). Further, the Government argues that Shaw, Mr. Charles, and

Black & Veatch’s methodological approach of determining fair market value in comparison to

similar projects’ EPC prices is improper. See ECF No. 80 at 35; ECF No. 91 at 19. In addition,

the Government contends that Luminate’s and Shaw’s reviews are irrelevant because they

concern estimations at a later point in time than the Desert Sunlight EPC Agreement prices set in

2011. See ECF No. 80 at 33, 35. As for the other evidence outlined above, the Government

either does not address it specifically or makes a conclusionary statement that they do not

establish fair market value. See ECF No. 91 at 20 n.14 (commenting on NextEra’s cost-buildup

27

that, “[e]ven disregarding the self-serving nature of this document, it is insufficient to establish

fair market value of tangible solar property.”); ECF No. 80 at 36 n.14 (after reviewing Deloitte’s

review process, commenting that “Deloitte did not determine the fair market value of the grant-

eligible assets.”).

Whether or not the Plaintiffs’ evidence establishes the EPC Agreement assets’ fair market

values, however, is a matter for determination at trial. The above evidence establishes that there

is a genuine dispute of material facts regarding the EPC Agreement assets’ fair market value and

whether Plaintiffs provided a sufficient I.R.C. § 1060 allocation in the form of Plaintiffs’ cost

segregations and Total Cost Spreadsheet containing the prices of the Transaction’s assets.

Accordingly, the Government’s summary judgment request is denied.

C. The Parties’ Motions for Partial Summary Judgment

Both Parties move for partial summary judgment. As an alternative to its summary

judgment motion, the Government seeks partial summary judgment that the DOE Loan

Guarantee and the LGIA are intangible assets and that, “as a matter of law, any consideration

that is properly allocable to the acquisition of these assets is not eligible for a § 1603 payment.”

Id. at 37. In contrast, Plaintiffs seek partial summary judgment that the DOE Loan Guarantee is

not a separable asset capable of reducing the basis of the Section 1603-eligible property, and thus

not included as part of the I.R.C. § 1060 allocation. ECF No. 86-1 at 2, 10-11; ECF No. 95 at

10. Further, Plaintiffs agree that the LGIA is an intangible asset ineligible for a grant under

Section 1603. See ECF No. 86-1 at 19-20. But Plaintiffs request summary judgment that the

LGIA is a Class VI asset, Id. at 20, while the Government contends that the LGIA is a Class V

asset, ECF No. 80 at 48. In addition, Plaintiffs ask the Court to rule that, for purposes of the

I.R.C. § 1060 allocation, there is no need to value Class VI or Class VII assets to determine the

appropriate allocation to Class V assets per their fair market value. ECF No. 86-1 at 2-3, 21.

Lastly, Plaintiffs seek that, as a matter of law, sales tax, interest during construction, and early

completion bonuses are included in the basis of the Section 1603-eligible assets. Id. at 3. The

Court will address each request in turn.

1. Alta Wind Resolves Two Arguments.

There are two issues for which the Parties seek summary judgment where the Federal

Circuit has squarely decided the issue. First, the Government asks the Court to determine that

the PPAs are intangible assets. ECF No. 80 at 37. Plaintiffs similarly ask the Court to rule that

the PPAs are intangible assets, but Plaintiffs also ask the Court to determine that the PPAs are

Class VI rather than Class V intangible assets. ECF No. 86-1 at 20. The Federal Circuit has

clearly held that “the PPAs . . . may be characterized as customer-based intangible assets under

I.R.C. § 197.” Alta Wind, 897 F.3d at 1373-74. As explained above, the Treasury Regulations

define I.R.C. § 197 intangible assets as Class VI assets. 26 C.F.R. § 1.338-6(b)(2)(vi) (“Class VI

assets are all section 197 intangibles, as defined in section 197, except goodwill and going

concern value.”); Alta Wind, 897 F.3d at 1376 (citing 26 C.F.R. § 1.338-6(b)). The Parties’

motions for summary judgment on this issue are granted.

28

Second, Plaintiffs seek the Court’s determination that, for purposes of the I.R.C. § 1060

allocation, the consideration in the Desert Sunlight Transaction must first be allocated to the

Class V assets to the extent of their fair market value, and only afterwards should any remaining

consideration be allocated to the Class VI and VII assets. ECF No. 86-1 at 3, 20. Here, too, the

Federal Circuit has spoken clearly. “The consideration is allocated among these classes in the

order they are listed in a ‘waterfall’ fashion, using the fair market value of the assets within each

class.” Alta Wind, 897 F.3d at 1376 (citing 26 C.F.R § 1.338-6(b)). Therefore, “[t]he purchase

price must . . . be allocated to Class V, then to Class VI, and finally to Class VII, if any value

remains.”) Id. (emphasis added). Plaintiffs’ motion for summary judgment on this issue is

granted.

2. The DOE Loan Guarantee’s Asset Status

The Government moves the Court to find that the DOE Loan Guarantee is an intangible

asset and that any allocable consideration to it is not eligible for a Section 1603 grant. ECF No.

80 at 37. Plaintiffs, however, move the Court to hold that the DOE Loan Guarantee is not a

separable asset capable of reducing the basis of the Section 1603-eligible property as part of the

I.R.C. § 1060 allocation. ECF No. 86-1 at 2, 10-11; ECF No. 95 at 10. The Court agrees with

Plaintiffs.

Plaintiffs largely rely on a March 2012 IRS Notice that “provides guidance in a question-

and-answer format on tax-related issues involving cash payments for specified energy property

in lieu of tax credits under Section 1603 of the American Recovery and Reinvestment Tax Act of

2009.” IRS Notice 2012-23, 2012-11 I.R.B. 483, 2012 WL 759615. Specifically, the Notice

states, in pertinent part:

Q-2. What are the federal income tax consequences to a taxpayer

who receives a Section 1603 payment and a Department of Energy

loan guarantee or an energy conservation subsidy from a public

utility?

A-2: Receipt of an incentive in addition to a Section 1603 payment

may reduce the eligible basis used in calculating the Section 1603

payment. (See FAQ1, Eligible Basis.) Receipt of a Department of

Energy loan guarantee does not reduce the basis of specified

energy property.

Id. ¶ Q-2 (emphasis added). According to Plaintiffs, the Notice “is squarely on point and

unambiguous: a DOE loan guarantee does not reduce eligible basis under ARRA Section 1603,

and thus none of the payments made with respect to the facility at issue are allocated to such loan

guarantees.” ECF No. 86-1 at 11.

Plaintiffs buttress their argument with the history of the energy tax credit. Id. at 11-13.

Specifically, Plaintiffs note that, prior to Section 1603’s amendment in 2009, the energy tax

credit provided that the eligible basis for the credit would be reduced by any “subsidized energy

financing.” Id. at 12 (citing I.R.C. § 48(a)(4) (2008)). “Subsidized energy financing”

encompassed any government financing for the purpose of subsidizing projects designed to

29

conserve or produce energy. Id. (citing I.R.C. § 48(a)(4)(C) (2008)). According to Plaintiffs, the

reason for the reduction was explained in the law’s legislative history: to prevent double-dipping

by investing in energy products with the aid of both government financing and a tax credit. Id. at

12 (citing H.R. Conf. Rep. No. 817, 96th Cong., 2d Sess. 1980, 1980 U.S.C.C.A.N. 642). And

equally clear, Plaintiffs contend, in the legislative history was Congress’ explicit carve-out:

“SUBSIDIZED FINANCING DOES NOT INCLUDE, HOWEVER, LOAN

GUARANTEES.” Id. (emphasis in original).

The Court need not wade into the legislative history on this point because the statute’s

language is clear. But Plaintiffs also point out that the IRS has interpreted the Code to exclude

loan guarantees from “subsidized energy financing.” The IRS adopted this understanding in

private letter rulings based on the same legislative history. ECF No. 86-1 at 12 (citing, e.g., PLR

8428035 (“The cited legislative history . . . clearly indicates that loan guarantees are not taken

into account in determining the credit reduction provided in [the ITC] and that loan guarantees

are not considered grants.”)). Plaintiffs add that this is even more true since 2009, when

Congress amended the energy tax credit so that subsidized financing would no longer reduce the

eligible basis, much less a government loan guarantee. ECF No. 86-1 at 13 (citing, e.g., I.R.C. §

1060 § 48(a)(4)(D)). Because Section 1603’s operation was designed to “mimic” the energy tax

credit, WestRock Virginia Corp., 941 F.3d at 1316 (“It is intended that the grant provision mimic

the operation of the credit under [IRC] section 48.”) (quoting H.R. Rep. No. 111-16 at 620–21),

Plaintiffs conclude that the energy tax credit’s non-reduction of an eligible basis by a

government loan guarantee is particularly relevant in concluding the same for a Section 1603

basis, ECF No. 86-1 at 13. While these IRS determinations are not binding, the Court may

consider them as persuasive authority. E.g., Glass v. Comm’r, 471 F.3d 698, 709 (6th Cir. 2006)

(“Although under I.R.C. § 6110(k)(3), a Private Letter Ruling cannot be used as precedent, a

recent ruling provides persuasive authority for refuting the Commissioner's argument.”). In this

case, the Court considers these letter rulings insofar as they shed light on the IRS’s

understanding of the Code and regulations at issue here.

In response, the Government argues that Plaintiffs’ cited authorities are irrelevant to the

Government’s position and the relevant issue surrounding the DOE Loan Guarantee. See ECF

No. 91 at 30-31. The Government does not argue that the DOE Loan Guarantee reduces a

Section 1603-eligible basis, as addressed in the above sources. See id. at 30-32. Rather, the

Government argues that the DOE Loan Guarantee must be included as an asset to which an

asset’s consideration is allocated under I.R.C. § 1060 to determine the Section 1603-eligible

basis. See id. at 30-31. In other words, “the issue is not whether the amount of the Loan

Guarantee, or the amount of guaranteed debt, is subtracted from basis; the issue is how § 1060

allocates the Transaction purchase price to establish § 1603-eligible basis in the first instance.”

Id. at 30. Thus, the Government maintains that neither the IRS Notice nor the energy tax credit

history are relevant to the allocability of the DOE Loan Guarantee under I.R.C. § 1060. See id.

at 30-31.

The Government’s argument draws a distinction without a difference. Even assuming the

DOE Loan Guarantee would be a Class V intangible asset under I.R.C. § 1060 as the

Government contends, ECF No. 80 at 48, including the DOE Loan Guarantee among the assets

to which consideration is allocated reduces a Section 1603-eligible basis.

30

Persuaded by the IRS Notice and the energy tax credit history, the Court agrees with

Plaintiffs that the DOE Loan Guarantee is not a separable asset to be included in the I.R.C. §

1060 allocation and reduce the Section 1603-eligible basis. Accordingly, the Court grants

Plaintiffs’ partial summary judgment request and denies the Government’s partial summary

judgment request as to the DOE Loan Guarantee’s asset status.

3. The LGIA’s Asset Class

As with the DOE Loan Guarantee, the Government requests that the Court find the LGIA

is an intangible asset and that any allocable consideration to it is not eligible for Section 1603

relief. Id. at 37. Partially agreeing with the Government’s request, Plaintiffs ask the Court to

determine that the LGIA is a Class VI asset specifically, ECF No. 86-1 at 20, in contrast to the

Government’s view that the LGIA is a Class V asset, ECF No. 80 at 48. The Court again

concurs with Plaintiffs.

Plaintiffs maintain that the LGIA is an intangible, Class VI asset under Section 197. ECF

No. 86-1 at 19. According to Plaintiffs, “[t]he LGIA is a contract wherein the CAISO and SCE

provide Plaintiffs the right to interconnect to the utility grid at a specified point,” which

“constitutes a ‘supplier-based intangible’ under IRC Section 197 – i.e., ‘the value resulting from

the future acquisition, pursuant to contractual or other relationships with suppliers in the ordinary

course of business, of goods or services that will be sold or used by the taxpayer.’” Id. (citing 26

C.F.R. § 1.197-2(b)(7)(i)). “Specifically,” Plaintiffs reason, “the LGIA reflects the value

resulting from Plaintiffs’ future acquisition, pursuant to contract, of interconnection services

from suppliers (CAISO and SCE) that will be used by Plaintiffs.” Id. Thus, Plaintiffs contend

that the LGIA is a Class VI intangible asset. Id. at 19-20.

The Government disagrees that the LGIA is a Class VI Section 197 asset, and specifically

not a supplier-based intangible. ECF No. 91 at 38 (citing 26 C.F.R. § 1.197-2(b)(7)(i)). The

Government reasons that “the LGIA is not a supplier-based intangible because there is no ‘future

acquisition’ occurring under the LGIA.” Id. Rather, according to the Government, “[t]he LGIA

represents the legal right for the Facility to interconnect to the grid,” and “plaintiffs acquired that

right in September 2011” when it “was contractually secured.” Id. “There was nothing left for

Desert Sunlight to acquire in the future from the [CAISO] under the LGIA (or from SCE, the

other party to the LGIA),” which the Government argues means that the LGIA is thus not a

supplier-based intangible asset “intended to capture value that results from a contract or other

arrangement that itself will permit the taxpayer to buy goods and services from a supplier in the

future.” Id.

The Government argues that the LGIA is not a supplier-based intangible because the

“example of a supplier-based intangible provided in the relevant regulation” of “an arrangement

that a taxpayer has with a retail store that allows the taxpayer to purchase in the future shelf

space in that store.” Id. (citing 26 C.F.R. § 1.197-2(b)(7)(i)) (emphasis in original). In that

example, according to the Government, “[t]he intangible asset is the ability to acquire the shelf

space in the future, which could have value because of uncertainty in the future of the

availability, or price of, shelf space.” Id. (emphasis in original). The Government contrasts that

to the LGIA where “plaintiffs are not acquiring . . . the ability to buy any good or service in the

future from CAISO, the relevant LGIA counterparty, or from any other party.” Id. “Plaintiffs

31

have simply secured a contract right that allows them to connect to the grid upon completion of

the Facility,” which “is entirely disconnected from the ‘future acquisition’ of a good or service

that is contemplated by the definition of a supplier-based intangible under Treas. Reg. § 1.197-

2(b)(7).” Id. “Therefore,” the Government concludes, “because the LGIA is not a supplier-

based intangible, it is not a section 197 intangible, and, thus is not Class VI asset. Consequently,

the LGIA falls within the general catch-all category of Class V asset.” Id. at 39.

The Government, however, misconstrues the definition of a Section 197 supplier-based

intangible. The federal regulation defines it as “the value resulting from the future acquisition,

pursuant to contractual or other relationships with suppliers in the ordinary course of business, of

goods or services that will be sold or used by the taxpayer.” 26 C.F.R. § 1.197-2(b)(7)(i). In

arguing that the LGIA is not a supplier-based intangible, the Government apparently assumes

that a “future acquisition . . . of goods or services” requires a new transaction in the future. But

that is too strict an interpretation. Rather, the future acquisition merely refers to a future transfer

of goods or services. Thus, even though the LGIA does not provide for any entirely new

transaction in the future, it does provide for the right to obtain a service in the future, i.e., the

right to interconnect to the grid. ECF No. 81-29 at App’x 2650, 2659, 2661-62. This is

precisely the definition of a supplier-based intangible under Section 197. And even if “future

acquisition” in the regulation encompassed actually acquiring something new, the LGIA meets

that definition as well, as it also requires SCE to construct a new substation to which Plaintiffs

will connect the Facility. Id.

Indeed, the example in the regulation that the Government cites supports the Court’s

understanding. The regulation specifically states that “the amount paid or incurred for supplier-

based intangibles includes, for example, any portion of the purchase price of an acquired trade or

business attributable to the existence of a favorable relationship with persons providing

distribution services (such as favorable shelf or display space at a retail outlet), or the existence

of favorable supply contracts.” 26 C.F.R. § 1.197-2(b)(7)(i). As Plaintiffs correctly note, in the

case of “shelf space in a store, the purchaser (a seller of consumer products) acquires from the

supplier (a grocery store or other retail outlet) – on the acquisition date itself – the right to use

designated shelf space in the future,” which “constitutes a supplier-based intangible . . . because

the agreement encompasses the right to receive a service in the future: the use of the shelf space

on an ongoing basis.” ECF No. 95 at 15. “Similarly,” they conclude, “while Plaintiffs received

the right to connect to the utility grid when First Solar conveyed the LGIA in September 2011,

the service itself – connectivity to the grid – was to be provided in the future, i.e., if and when the

Desert Sunlight facility began to operate, and continuously thereafter.” Id.

In fact, Plaintiffs correctly observe that “the LGIA is an even clearer example of a

supplier-based intangible[]” than the shelf space example. Id. at 16. “In the case of shelf space

in a retail outlet,” Plaintiffs continue, “a party receives the contractual right to use shelf space in

the future, but the regulations suggest that the party also may begin using shelf space on Day 1,

immediately after it acquires the right.” Id. “Given that the contract[] . . . ha[s] been deemed to

convey ‘value resulting from the future acquisition’ of a good or service, and thus constitute [a]

supplier-based intangible[], then a fortiori, the LGIA – under which Plaintiffs would only be

interconnecting to the grid years after acquiring the contract in September 2011 – is

a . . . supplier-based intangible.” Id. (emphasis omitted).

32

Therefore, the Court agrees with Plaintiffs that the LGIA is a Class VI Section 197

supplier-based intangible asset. Alternatively, even if the Court had not agreed with the

Plaintiffs that the LGIA is a supplier-based intangible asset, the LGIA would still presumably be

a Class VI Section 197 intangible asset under 26 C.F.R. § 1.197-2(b)(12), which provides that

“Section 197 intangibles include any other intangible property that is similar in all material

respects to the property specifically described in . . . paragraphs (b)(3) through (7) of this

section.” 26 C.F.R. § 1.197-2(b)(12). As Plaintiffs correctly note, the LGIA is materially similar

to supplier-based intangible assets because it too “confers the right to receive something in the

future on specified terms.” ECF No. 95 at 17. Thus, the LGIA would still be a Class VI Section

197 intangible asset. As a result, the Court grants the Government’s summary judgment motion

insofar as it seeks judgment that the LGIA is an intangible asset, as well as Plaintiffs’ partial

summary judgment motion insofar as it seeks judgment that the LGIA is a Class VI Section 197

intangible asset.

4. Operation of I.R.C. § 1060’s Allocation

Plaintiffs’ next move for summary judgment that “[u]nder the I.R.C. § 1060 waterfall,

there is no need to value Class VI or Class VII intangibles in order to determine the appropriate

allocation to Class V assets.” ECF No. 86-1 at 21. For purposes of allocating consideration to

Class V’s assets, Plaintiffs explain, “it is only necessary under IRC § 1060 to determine the fair

market value of the Class V assets, and to allocate to Class V in accordance with that fair market

value. That determination is made without regard to any purported value that Class VI or VII

intangibles might have.” Id.

In response, the Government asserts that, while it is true that there may be no

consideration left to be allocated to the Class VI or VII assets after allocation to the Class V

assets, “[t]hat factual determination[] . . . does not alter the taxpayer’s legal requirement to set

forth its determination of the fair market value associated with each asset class under § 1060.”

ECF No. 91 at 40 (emphasis in original). “A taxpayer’s belief that its purchase price should be

allocated in a way that renders the value of Class VI intangible assets irrelevant does not excuse

the taxpayer from the requirement to inform the government of the fair market of the Class VI

intangible assets.” Id. (emphasis omitted). Noting that Plaintiffs’ failure to value all of the

Desert Sunlight Transaction’s assets subjected them to penalties under the Internal Revenue

Code, the Government explained that “[t]here is a good reason that plaintiffs were required to

provide this information to the government. It provides the government with the ability to

review the totality of the circumstances and determine whether to accept or challenge the

taxpayer’s stated fair market values and related allocation. . . .” Id. However, the IRS “may

challenge the taxpayer’s determination of the fair market value of any asset by any appropriate

method and take into account all factors . . . .” Id. (quoting 26 C.F.R. § 1.338-6(a)(2)(iii)).

“Without the taxpayer’s view on the valuation of all the assets acquired, neither the government

nor the court can evaluate the totality of the circumstances,” which the Government argues “is

especially important when the application of § 1060 involves a consideration of [‘]all the facts

and circumstances.[’]” Id. at 41 (quoting 26 C.F.R. § 1.1060-1(b)(2)(iii)).

The Government’s argument is unpersuasive. As an initial matter, the Government’s

argument that Plaintiffs’ failure to provide fair market values for Class VI and VII property

deprived it of the ability to determine whether to challenge the Plaintiffs’ asset valuations is

33

belied by the fact that the Government is clearly challenging the Plaintiffs’ asset valuations. But

as explained above, those challenges are factual ones for trial, not summary judgment. Among

those factual issues will be the fair market values of the assets Plaintiffs acquired in the

Transaction.

Because this is a Section 1603 cash grant case, what matters most is the value of the

Class V tangible assets in which the Section 1603-eligible tangible assets fall, not the value of

the Class VI or VII intangible assets. As already analyzed at length, Plaintiffs mustered

sufficient evidence concerning the fair market value of the Class V tangible assets to survive

summary judgment. See supra III.A.2(b)(2)-(3). If Plaintiffs prove these fair market values at

trial, all the Transaction consideration would be allocated to Class V and the fair market value of

the Class VI and VII assets would not be necessary. Of course, if the Government shows errors

in Plaintiffs’ valuations, there may be consideration left over to allocate to Class VI or VII assets.

This too is a trial issue. And while the Government appears to disagree, the Plaintiffs have come

forward with analyses of the Class VI assets by KPMG and their proposed expert Mr. Charles

that both found these assets to have no or negligible value. See ECF 87 at 68-70 (summarizing

evidence). This too shall be resolved at trial.

The Court grants Plaintiffs’ third request for partial summary judgment that, for purposes

of the I.R.C. § 1060 allocation, there is no need to value Class VI or Class VII intangibles in

order to determine the appropriate allocation to Class V assets per their fair market value.

5. Sales Tax, Interest During Construction, and Early Completion Bonuses

Plaintiffs’ fourth request for partial summary judgment is for the Court to determine that,

as a matter of law, sales tax, interest during construction, and early completion bonuses are

included in the basis of the Section 1603-eligible assets. Id. at 3. In making their request,

Plaintiffs are clear that they do not seek the Court to decide the amount of the sales tax, interest

during construction, and early completion bonuses that should be included in the basis, as that

determination is an issue for trial. Id. at 21. Rather, Plaintiffs merely request that the Court find

that these cost categories are included in the basis as a matter of law. Id.

The Government “does not dispute that in general sales tax and interest are subject to the

capitalization rules of § 263A, and in general are § 1603-eligible costs if incurred in connection

with the acquisition of specified energy property under § 1603 and Treasury Guidance.” ECF

No. 91 at 41. The Government similarly does not dispute that early completion bonuses, as a

matter of law, may be included in the eligible basis. See id. at 42-45 (only addressing why the

early completion bonuses in this case should not be included in the basis, but not disputing that

they may be included as a matter of law).

Indeed, that sales tax, interest during construction, and early completion bonuses are

included in the basis of Section 1603-eligible assets as a matter of law is generally not a matter

of dispute. See ECF 88 at App’x 249 (“Basis . . . may also include the capitalized portion of

certain other costs related to buying or producing the property (e.g., permitting, engineering, and

interest during construction).”) (citing 26 C.F.R. § 1.263A-1). Section 263A of the U.S. Code,

Title 26, requires that certain costs incurred in producing certain property must be capitalized to

that property, I.R.C. § 263A(a)(1)(B), meaning “charge[d] to a capital account or basis,” 26

34

C.F.R. § 1.263A-1(c)(3). Section 263A applies to “[r]eal or tangible personal property produced

by the taxpayer,” I.R.C. § 263A(b)(1), and specifically “property produced by the taxpayer for

use by the taxpayer . . . in a trade or business or an activity conducted for profit,” I.R.C. §

263A(c)(1). “Produc[ing]” property refers to constructing, building, installing, manufacturing,

developing, or improving property, I.R.C. § 263A(g)(1), and “[t]he taxpayer shall be treated as

producing any property produced for the taxpayer under a contract with the taxpayer . . . ,” I.R.C.

§ 263A(g)(2). The costs to be capitalized with such property include both “direct costs” and

“indirect costs.” I.R.C. § 263A(a)(2). Indirect costs “directly benefit or are incurred by reason

of the performance of production . . . .” 26 C.F.R. § 1.263A-1(e)(3)(i).

There are many examples of indirect costs that are capitalized to the costs to produce

property under Section 263A. One example is taxes, I.R.C. § 263A(a)(2)(B), “to the extent such

taxes are attributable to labor, materials, supplies, equipment, land, or facilities used in

production . . . .” 26 C.F.R. § 1.263A-1(e)(3)(ii)(L). Indirect costs also include interest costs

“paid or incurred during the production period, and [] allocable to property . . . which has (i) a

long useful life, (ii) an estimated production period exceeding 2 years, or (iii) an estimated

production period exceeding 1 year and a cost exceeding $1,000,000.” I.R.C. § 263A(f)(1); see

also 26 C.F.R. § 1.263A-1(e)(3)(ii)(V) (“Interest includes interest on debt incurred or continued

during the production period to finance the production of real property or tangible personal

property to which section 263A(f) applies.”). Lastly, early completion bonuses have been

determined to be capitalized under Section 263 of the U.S. Code, Title 26, which generally

requires the capitalization of “[a]ny amount paid out for new buildings or for permanent

improvements or betterments made to increase the value of any property or estate.” I.R.C. §

263(a)(1); see Rev. Rul. 70-332, 1970-1 C.B. 31, 1970 WL 20683, at *2 (concluding that “the

premium time or overtime . . . paid or incurred solely to expedite the installation of additional

stands in the rolling mill is not an ordinary and necessary business expense to be deducted” but

instead, “under section 263(a) of the Code, such amount is added to the primary cost of the

installation.”); see also, e.g., Sears Oil Co. v. Comm’r, 359 F.2d 191, 197 (2d. Cir. 1966)

(holding in part that payments for early delivery of oil barges cannot be deducted as ordinary and

necessary business expenses but were capital expenditures).

Accordingly, the Court grants Plaintiffs’ fourth ground for summary judgment, that, as a

matter of law, the cost categories of sales tax, interest during construction, and early completion

bonuses are capitalized to the costs included in the basis of the Section 1603-eligible assets.

IV. Conclusion

For the foregoing reasons, the Court hereby rules:

1. The Government’s Motion for Summary Judgement, ECF No. 80, is GRANTED-IN-

PART and DENIED-IN-PART;

2. Plaintiffs’ Cross Motion for Partial Summary Judgment, ECF No. 86, is GRANTED;

and

35

3. The Government’s Motion in Limine to Exclude Inadmissible Testimony Offered by

Plaintiffs’ Witnesses, ECF No. 92, is DENIED AS MOOT without prejudice to object

at trial.

The Court will schedule a status conference in the week of October 18, 2021, to

determine the date and location of trial.

IT IS SO ORDERED.

s/ Edward H. Meyers

Edward H. Meyers

Judge

36