Claim of Right

INTERNAL REVENUE SERVICE
NATIONAL OFFICE TECHNICAL ADVICE MEMORANDUM
March 31, 2006
Third Party Communication: None
Date of Communication: Not Applicable
Index (UIL) No.: 61.09-01
CASE-MIS No.: TAM-135331-05
Number: 200631023
Release Date: 8/4/2006
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Taxpayer's Name: ---
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Taxpayer's Address: ---
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Taxpayer's Identification No ---
Year(s) Involved: ---
Date of Conference: ---
LEGEND:
LEGEND:
Taxpayer = ---

Parent = ---
State A = ---
Date 1 = ---
Date 2 = ---
Date 3 = ---
Date 4 = ---
Date 5 = ---
Date 6 = ---
Date 7 = ---
Date 8 = ---
Tax Year 1 = ---
The Act = ---
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Section A = ---
Section B = ---
TAM-135331-05 2
Section C = ---
Plant = ---
$a = ---
$b = ---
$c = ---
$d = ---
$e = ---
$f = ---
$g = ---
$h = ---
$i = ---
$j = ---
$k = ---
$l = ---
$m = ---

# ISSUE

Whether certain gain proceeds from the sale of the Taxpayer’s generating assets are includible in gross income under § 61 of the Internal Revenue Code in the tax year of the sale of the assets.

# CONCLUSION

The proceeds from the sale of the Taxpayer’s generating assets were received under a claim of right and were, therefore, includible in gross income under § 61 of the Code in the year of sale.

# FACTS

Taxpayer owns operating electric utilities, including Subsidiaries 1 and 2 (collectively “Companies”). On Date 1, Taxpayer merged into Parent. On Date 2, State A enacted the Act, which restructured its electric utility industry in order to create direct access by retail customers to the competitive market for electricity. The Act recognized that in order to serve their customers, public utilities had undertaken long-term investments in generation, transmission and distribution facilities and had entered into long-term power supply agreements as required by federal law. These investments and agreements have created costs which may not be recoverable in a competitive market. These costs are known as “transition or stranded costs.” Companies were impacted by the Act.
Section A of the Act defines “transition or stranded costs” as an electric utility’s known and measurable net electric generation-related costs determined on a net present value basis over the life of the asset or liability as part of its restructuring plan, which traditionally would be recoverable under a regulated environment but which may not be recoverable in a competitive electric generation market and which the Public Utilities TAM-135331-05 3 Commission (“Commission”) determines will remain following mitigation by the electric utility. This term includes certain costs and charges including those relating to regulatory assets and other deferred charges (i.e., the unfunded portion of the utility’s projected nuclear generating plant decommissioning costs and cost obligation under contracts with nonutility generating projects which have received a Commission order); prudently incurred costs related to cancellation, buyout, buydown, or renegotiation of nonutility generating projects relating to cogeneration rules and regulations; and numerous other costs. The Act empowered the Commission to determine the level of transition or stranded costs for each electric utility and to permit the utility to recover an appropriate amount of such costs through a “competitive transition charge” (“CTC”), which is a nonbypassable charge applied to the bill of every customer accessing the transmission or distribution network and which is designed to recover an electric utility’s transition or stranded costs as determined by the Commission.
Section B of the Act governs public utility restructuring plans. It requires the unbundling of electric utility services, tariffs and customer bills to separate the charges for generation, transmission and distribution; authorizes various rate caps during the transition period; and provides that the Commission may permit, but shall not require, an electric utility to divest itself of facilities or to reorganize its corporate structure.
Section C of the Act provides that each electric utility will be able to recover its transition or stranded costs, through the CTC, from every customer accessing its transmission or distribution network. The transition or stranded costs recoverable through the CTC include: (i) regulatory assets and other deferred charges typically recoverable under current practice, the unfunded portion of the utility’s projected nuclear generating plant decommissioning costs and cost obligations under contracts with nonutility generating (“NUG”) projects that have received a Commission order; (ii) an electric utility’s prudently incurred costs related to cancellation, buyout, buydown or renegotiation of nonutility generating (“NUG”) projects; and (iii) other generation-related transition or stranded costs that may be recovered through the CTC. Section C also provides that in determining the level of transition or stranded costs that an electric utility may recover through the CTC, the Commission shall consider the extent to which the electric utility has undertaken efforts to mitigate generation-related transition or stranded costs.
Section C imposes a duty to mitigate transition or stranded costs on electric utilities throughout the transition period by several methods including the reduction of book assets by application of new proceeds of any sale of idle or under-utilized existing rate base generation assets.
The Act required all State A electric utilities to submit a restructuring plan to the Commission. Companies filed a restructuring plan. The Commission was required to determine what portion of Companies' assets would become uneconomic (or stranded) in the new unregulated market for generation and to develop an appropriate rate (CTC) that will permit it to recover those stranded costs over a reasonable period of time from ratepayers. In determining stranded costs, the Commission acknowledged that TAM-135331-05 4 Companies stated that they would divest generating assets (fossil and nuclear assets) through an auction process and private sale, which offered potential for mitigating stranded costs of Companies. On Date 3, the Commission entered its Opinions and Orders approving the proposed restructuring plan and allowing recovery of certain stranded costs, the amount of which was determined by the generation assets’ market value in excess of book values. However, Companies objected to the methodology used by the Commission for determining the amount of certain stranded costs.
After hearings and negotiations, all parties to the restructuring of the Companies reached “Joint Petition for Full Settlement” (“Settlement”) on Date 4 resolving all issues concerning Companies’ restructuring plan. Pursuant to the Settlement, the Commission would approve and implement the full Settlement, including approval of Companies’ transfer of generation assets. The Settlement permits Companies to recover certain stranded costs and requires the use of the net proceeds from the sale of generation assets to mitigate or offset stranded costs. Under the terms of the Settlement, Companies will sell its generation assets at fair market value to third parties.
Companies agreed that 100 percent of all State A-jurisdictional net divestiture proceeds (which are defined in the Settlement as the difference between the selling price of the generation assets and the sum of (i) the net book value of the assets and (ii) the incremental transaction costs incurred in selling the assets) would be used to offset stranded costs, in the following order of priority: (1) the balance of Company-owned generation costs; (2) regulatory assets (including NUG buyouts and prior NUG deferrals); (3) nuclear decommissioning costs; and (4) operating NUG Costs.
Subsidiary 1 on an interim basis was permitted to recover from its retail customers $b of stranded assets and costs through a CTC (to remain in effect from Date 6 to Date 7) that includes a separate accounting mechanism to track the recovery of operating NUGrelated stranded costs which will continue in effect until all NUG contracts have terminated, provided that it expires no later than Date 8, which is several decades after Date 6. Similarly, Subsidiary 2 was permitted to recover $c from its retail customers in stranded assets and costs. The Parties agreed that this Settlement and the NUG Cost recovery mechanism, initially through the CTC and subsequently through a separate recovery mechanism, would provide for full and actual cost recovery of all costs and charges for energy and capacity existing under the NUG agreements. During the period from Date 6 through Date 8, Companies are required to submit quarterly and annual reports to the Commission addressing the recovery of actual NUG-related costs through the CTC. Periodically, the Commission and the Companies will readjust CTCs to recover Companies’ actual, rather than estimated, operating NUG costs. Under the Settlement (which was incorporated into the Final Order, see below), the CTC would be reflected in the rate charged to ratepayers for electricity and was to be separately stated along with distribution charges, transmission charges and generation shopping credits.
The Settlement also required that, as of Date 6, Companies would establish and maintain “NUG Trusts” into which Companies were to deposit, net of tax, any net TAM-135331-05 5 proceeds from the sale of their generating assets above the amounts of their non-NUG stranded costs. The use of trusts was not required by the Act, but rather were the product of negotiation between the Commission and the Companies in order to provide for the recovery of actual NUG costs. Companies thus are assured of full cost recovery of their contractual obligations relating to non-utility generation projects. The Settlement states that, “The primary purpose of these separate NUG Trusts is to ensure an actual source of cash from which the Companies can pay their respective on-going NUG obligations under existing NUG power purchase contracts. Ratepayers are entitled to any remaining amount in the NUG Trusts after the Companies’ NUG obligations have been met in full.” Companies must use reasonable efforts to maximize the earnings on funds in the NUG Trusts consistent with the type and nature of risk associated with these types of investments and the need to make future payments to NUGs from such funds. Companies remain obligated to pay the NUG contract costs regardless of the existence of the NUG Trusts or adequacy of funds therein at any particular point in time.
If either Company’s cumulative NUG CTC revenues and any funds in the applicable NUG Trust are less than its actual above-market NUG costs, that Company (i.e., Subsidiary 1 and 2) shall be entitled to defer all such sums on their books for future recovery from customers.
The Settlement provides that subject to any prior adjustment to the CTC resulting from the final outcome and accounting for the net proceeds of the Companies’ sales of their generating assets, every 5 years the Companies shall each file with the Commission a written NUG Statement comparing (i) their respective NUG CTC revenues as of the date of that statement with (ii) each Company’s actually incurred above-market costs over the same period. The NUG Statements must contain (for the period covered by the statement) a summary of actual market value of the NUG project’s energy, actual market value of the capacity associated with the applicable NUG contract, NUG project output, any NUG buy-outs, NUG contract rates, NUG mitigation efforts and other pricing variables. The Commission will consider whether this summary results in higher or lower NUG-related costs than were projected previously for purposes of this Settlement.
After consideration of each NUG Statement, the Commission will adjust the amount or the duration of the CTC rate, or the successor recovery mechanism, in order to reconcile the Companies’ actual NUG costs for the applicable period with the amounts previously reflected in each of the Companies’ CTCs. Companies must file a separate final NUG Statement in the Date 8 year, which the Commission will review and then enter an order addressing the final reconciliation of any over or under recoveries of NUG costs in the Companies’ respective CTCs.
On Date 5, the Settlement was approved and made final (“Final Order”). The Final Order included the Commission's approval of the sale of Companies' generating assets and the requirement that all of Companies’ State A-jurisdictional net divestiture proceeds will be used by the Companies to offset stranded costs including the payment of operating NUG obligations. Accordingly, prior to the sale of any assets, the Final Order incorporating the Settlement was in place.
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In Tax Year 1, Taxpayer sold its generating assets to third party buyers for an amount, net of certain adjustments, of $d. The assets had a book value of $e, but a tax basis substantially less. Taxpayer reported all of the gains from the sales of its generating assets on Form 4797. After certain audit adjustments, Taxpayer will have a section 1231 gain, which is afforded the benefit of being treated as a capital gain on the Tax Year 1 tax return. On its tax returns for Tax Year 1 and for subsequent tax years, Taxpayer claimed ordinary deductions for various stranded costs that were identified and offset with net divestiture proceeds. These included decommissioning costs, tax basis of nuclear assets, and other deductions. In later tax years, Taxpayer and Parent incurred substantial capital losses, which have been carried back into the Tax Year 1 and are offsetting the capital gains reported on the Tax Year 1 tax return.

The interplay between net divestiture proceeds and stranded costs is shown in a Report on Actual Net Divestiture Proceeds and Reconciliation of Stranded Costs. This Report indicates that the $f of net divestiture proceeds from Plant sales were treated as negative stranded costs and offset against the following stranded costs in Tax Year 1, the year in which the assets were sold:

(1) Book basis of $g in a nuclear plant after the sale;

(2) Regulatory assets of $h (including the buyout costs of NUG contracts, deferred energy costs, clean-up of an ash site over time, dam restoration costs, unamortized loss on reacquired debt and payment for deferred income taxes);

(3) Energy costs paid in earlier years of $i;

(4) NUG Buyouts of $j; and (5) Decommissioning costs for two nuclear power units of $k. After the above offsets, $l of negative stranded costs remained and were placed into a NUG Trust to cover the operating NUG contracts.

Operating NUG contracts are stranded costs that represent payments to be made for the contractual purchase of energy from non-utility generators. These NUG costs were above market charges and were to be paid through a collection of the CTC from ratepayers and the withdrawal of divestiture proceeds from the NUG Trust. Therefore, Taxpayer’s non-NUG stranded costs were fully recovered through net divestiture proceeds. Net divestiture proceeds in excess of non-NUG stranded costs were placed in the NUG Trust per the Settlement and Final Order. Although Taxpayer’s CTC rate does not fully recover operating NUG costs each year, it is able to fully collect its operating NUG costs by withdrawing proceeds from the NUG Trust. These withdrawals keep the Taxpayer current in its collection of operating NUG cost obligations.

# LAW AND ANALYSIS

Section 61 defines gross income as "all income from whatever source derived." Section 61(a)(3) specifically refers to "gains derived from dealings in property" as an item of gross income. A taxpayer must recognize the gain from the sale of property, unless the gain is otherwise excluded by law. Section 1.61-6 of the Income Tax Regulations.
The above definition of gross income must be considered in the context of the claim of right doctrine, which has evolved from cases such as North American Oil Consolidated TAM-135331-05 7 v. Burnet, 286 U.S. 417 (1932). In that case, the court held that "[i]f a taxpayer receives earnings under a claim of right and without restrictions as to its disposition, he has received income" and accordingly must be taxed on it. Id. at 424. However, where a taxpayer is obligated to dispose of the money it receives in a certain way, accruing no benefit to itself, the money is not includible in the taxpayer's gross income. See Central Life Assurance Society v. Commissioner, 51 F.2d 939, 941 (8th Cir. 1931).
While the United States Supreme Court has not directly addressed the precise set of facts presented by this case, it has addressed the income tax treatment of amounts received by utilities in other circumstances. In Commissioner v. Indianapolis Power & Light Co., 493 U.S. 203 (1990), an electric utility ("IPL") required certain customers with suspect credit to make deposits to insure prompt payment of future utility bills. The customer was entitled to a refund of the deposit after making timely payments for several months or satisfying a credit test. The customer could choose to take the refund by cash or check or to apply the refund against future bills. The deposits were commingled with other receipts and at all times were subject to IPL's unfettered use and control. The Service argued that the deposits were advance payments immediately includable in income, while IPL argued they were analogous to loans and, as such, not taxable. The Court reasoned that in economic terms the distinction between advance payments and loans was one of degree rather than kind. Id. at 208. While both bestow economic benefits to the recipient, economic benefits qualify as income only if they are "undeniable accessions to wealth, clearly realized, and over which the taxpayers have complete dominion." Id. at 209, quoting Commissioner v. Glenshaw Glass Co., 348 U.S. 426, 431 (1955). The key to determining whether a taxpayer enjoys "complete dominion" over a given sum is whether the taxpayer "has some guarantee that he will be allowed to keep the money." Indianapolis Power and Light, 493 U.S. at 210. The proper focus is on the rights and obligations of the parties at the time the payment was made. Id. at 209. Because IPL's customers controlled the ultimate disposition of the deposit and had not committed to purchasing any electricity at the time the deposit was made, the Court found that IPL had no guarantee that it would be allowed to keep the money and held that the deposit amount was not income.
A long line of cases has consistently held that when a taxpayer receives funds with an unequivocal statutory or regulatory duty to repay them, thus receiving no economic benefit from the funds, they are not includible in gross income at the time of receipt. For instance, in Illinois Power Co. v. Commissioner, 792 F.2d 683 (7th Cir. 1986), rate increases collected by the taxpayer utility, pursuant to a state commerce commission's order to discourage consumption, were not includable in gross income in the years received because such increases were not intended to enrich, nor be retained by, the taxpayer. The taxpayer was required to repay these extra amounts to customers in later years even though the customers obtaining the benefit of the repayments were not the same as the customers who paid the increased rates. See also Mutual Telephone
Co. v. United States, 204 F.2d 160 (9th Cir. 1953).
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A number of recent cases address the tax consequences of fuel overrecoveries to the utilities collecting such overrecoveries. In Houston Industries, Inc. and Subsidiaries v.
United States, 125 F.3d 1442 (Fed. Cir. 1997), fuel cost overrecoveries received by the utility taxpayer were excludable because the taxpayer had a statutory obligation to repay such amounts to customers. Thus, the taxpayer did not have unrestricted dominion and control over such amounts when received. The Court reasoned that it did not matter whether the amounts were refunded by check to customers or offset against customers' bills because either method had the same effect. In Florida Progress Corporation & Subsidiaries v. Commissioner, 114 T.C. 587 (2000), overrecoveries of estimated fuel and energy conservation costs were excludable because the utility did not have complete dominion and control over such amounts upon receipt. Regulatory authority required the taxpayer to return overrecoveries with interest to customers. The repayment mechanism afforded the taxpayer no opportunity to benefit from overrecoveries and the taxpayer was subject to a fixed and certain liability to refund overrecoveries that were determinable when the funds were received. In Cinergy Corp. v. United States, 55 Fed Cl. 489 (2003), the taxpayer was not required to recognize fuel cost overrecoveries as income when received because (1) it was required to return overrecoveries to its customers; and (2) it lacked complete dominion over the funds, as evidenced by the fact that the time and method of refund was controlled by the regulatory authorities and the taxpayer was required to make monthly reconciliation of these accounts to the regulators.1 As set forth in the Facts, part of the $f in gain proceeds was used to offset non-NUG stranded costs in the Tax Year 1, the tax year of receipt. There is no dispute between the Field and the Taxpayer that this amount of the gain proceeds is includible in the Taxpayer’s gross income in that year. The parties disagree strongly on whether the $l amount of the gain proceeds, which was placed in the NUG Trust, is also included in Taxpayer’s gross income in the tax year of receipt or deferred from gross income until actually used to offset stranded costs associated with the operating NUG costs.
Citing the above cases, the Field argues that the gain proceeds are not includible in gross income in the tax year of the sale since the statutory and regulatory scheme established by State A requires that such amounts be used to mitigate the amount of the CTC that would otherwise be billed to ratepayers. The economic benefits from the sale of the generation assets thus inure to the ratepayers, rather than to the Taxpayer, in the form of lower CTCs than they would have otherwise had to pay. Since it has a binding obligation to pay the gain proceeds to the ratepayers, or on their behalf, by reducing stranded costs, the Field concludes that the Taxpayer lacks a claim of right to the gain proceeds until such proceeds are used to offset stranded costs. The Field also 1 In Rev. Rul. 2003-39, 2003-17 I.R.B. 811, the Service accepted the holdings in Houston Industries, Florida Progress, and Cinergy Corp. and indicated that it will follow those cases in situations involving substantially similar facts.
TAM-135331-05 9 argues that the gain proceeds should not be includible in gross income in Tax Year 1 since the trust imposed substantial restrictions on the Taxpayer’s access to the funds.
The Taxpayer asserts that its agreement to use the gain proceeds from the sale of the assets to mitigate or reduce CTCs recoverable from ratepayers does not equate to an unequivocal statutory or regulatory duty to repay such proceeds to the ratepayers within the meaning of the above line of cases. Taxpayer’s position is that as a result of the bargaining process with the Commission, it was entitled to retain the gain proceeds and to use such funds as a source of funds to recover its actual operating NUG costs. It therefore received the economic benefits from the gain proceeds, and thus the full amount of the gain proceeds are includible in gross income at the time of receipt.
It is apparent that the Taxpayer is statutorily entitled to receive an amount of CTC sufficient to recover its transition or stranded costs. It is also a fact that the sale of the generating assets did reduce the amount of CTCs ultimately chargeable to ratepayers from the amount of CTCs that the ratepayers would have otherwise had to pay if the Taxpayer is to fully recover its stranded costs. Accordingly, Taxpayer became entitled to recover its transition or stranded costs from two sources: the ratepayers or plant sales. In our view, amounts from either source constitute income when received. While the amounts recovered from plant sales may not be recovered again from ratepayers, and thus may constitute a benefit of sorts to ratepayers in the form of reduced CTCs collected from them, this factor, at best, is incidental to the more significant, obvious and direct benefit Taxpayer received under the Settlement and the Final Order: the right to receive and retain the gain proceeds from plant sales, including $l placed in the NUG Trusts and earmarked for use in meeting its obligations to pay operating NUG costs.
This case is also distinguishable from the court cases cited above. In the overrecovery cases, the taxpayers collected amounts that they were not, by statute, permitted to keep (thus the use of the term “overrecovery” in the cases). Here, the gain proceeds cannot be considered “overrecoveries” that the Companies were not permitted to keep under the Act. Rather, the Act provides that the sale of assets is a method of mitigation of stranded costs, but it does not specifically require the utility to repay or return the proceeds from such sales to ratepayers (e.g., as a cash refund, credit on their bills, etc.). The Taxpayer sold assets and was entitled to keep the amounts it received from the sale of its plants. The Commission and the Taxpayer agreed that Taxpayer would apply the gain proceeds as a reduction to the CTC balance estimated by the Taxpayer as sufficient to recover its stranded costs, including its actual operating NUG costs. As a consequence, the gain proceeds reduced the CTC amount the ratepayers would have otherwise have had to pay in later years. Such offset does not, however, equate to the refund of an overrecovery. In other words, the ratepayers ultimately were not the sole source of funds to which Taxpayer was entitled for recovery of its stranded costs. The gain proceeds from plant sales became a second source, which served as an offset to what could otherwise be levied in the form of rates charged to ratepayers. They were also, like the CTC rates, includible in income. The same would be true in the case of a TAM-135331-05 10 taxpayer who performs a service for which he is entitled to $100 compensation from Source A or Source B, but not both. In such a case, the taxpayer has gross income of $100 when Source A makes his required payment even though that payment completely offsets the amount owed by Source B.
Another notable difference in this case is that the gain proceeds were received from third party purchasers of Taxpayer’s generating assets, not from the ratepayers themselves. The court cases and revenue rulings in this area are not on point with respect to the sale of assets in a situation similar to the instant case.
Furthermore, the Act does not require a utility to sell its generating assets. Nor does the Act specifically state that the proceeds from the sale of the assets inures to the benefit of ratepayers. Instead, the Act recognizes that a utility has the right to fully recover its transition or stranded costs and provides that the CTC is the mechanism by which such recovery will be made. The Act thus contemplates that the CTC is intended to render an economic benefit to the utility by compensating it for any losses due to stranded costs resulting from deregulation. The fact that the sale of assets by a utility reduces the amount of CTCs charged to ratepayers in no way reduces the total amount of that economic benefit to the utility. It therefore cannot be said that a mitigation or reduction in CTCs charged to ratepayers by the amount of gain on the sale of assets is the equivalent of a duty to repay the proceeds from such sale to ratepayers. Consequently, this situation is distinguishable from the overrecovery cases where the utility was not entitled to retain the amount of the overrecovery in the tax year collected. 2 Unlike the 2 The Field argues that the fact that the Settlement states that ratepayers are entitled to any amounts remaining in the NUG Trusts after the Companies’ NUG obligations have been met in full supports its position that the gain proceeds benefit ratepayers. It thus analogizes this case to the overrecovery cases. The Settlement does use such terminology with respect to the final NUG Statement which the Companies will file with the Commission for the Date 8 year. In that year, which is decades after the year of sale, the Commission will issue a final reconciliation of any over or under recoveries of NUG costs in the Companies’ respective CTCs. Any funds remaining in the NUG Trusts would then be returned to ratepayers (however, if cumulative NUG CTC revenues and the funds in the NUG Trusts are less than actual above-market NUG costs, the difference will be recovered from ratepayers). We think that this equates to a contingent refund obligation that the Taxpayer may have to meet many years in the future. Such contingencies do not necessarily entitle a seller to delay recognizing income until the time during which the contingencies could have materialized is past.
See, e.g., Continental Illinois Corp. v. Commissioner, 998 F.2d 513, 520-21 (7th Cir.
1993), cert denied, 510 U.S. 1041 (1994)(Interest income received by bank held includible in gross income even though such interest was received subject to a contingent obligation to rebate it to customers). Accordingly, the possibility many years in the future that the Companies may have to pay or refund some of the funds in the NUG Trusts to the ratepayers does not somehow convert the proceeds from the sale of the Taxpayer’s assets into the ratepayers’ funds and thus should not preclude the TAM-135331-05 11 taxpayers in Houston Industries, Inc., and similar cases, the Taxpayer had unrestricted dominion and control over the gain proceeds from the asset sales when received, and the only “detriment” to Taxpayer in receiving its “CTC” via the sale of assets was that it could not again collect such amount from the ratepayers.
The Field also asserts that there are substantial restrictions on the Taxpayer’s access to the gain proceeds, which preclude the inclusion of such amounts in gross income in the year of sale. See North American Oil Consolidated, 286 U.S. at 424. First, the Field notes that the Taxpayer entered into the binding Settlement before the asset sales, and that the Settlement required gain proceeds to offset certain stranded costs, with the remaining proceeds being placed in the NUG Trust. Second, the trust money could only be used to pay future NUG obligations. Third, all earnings (e.g., interest) on the trust funds further reduced ratepayers’ NUG obligations. The Field concludes that these facts constitute substantial restrictions on the gain proceeds, which prevent them from being taxable until used to offset against the stranded costs, both NUG and non-NUG.
In support for this argument, United States v. Maryland Jockey Club, 210 F.2d 367 (4th
Cir. 1954), is cited. There, a state law required a race track operator to pay over to the state racing commission a percentage of its gross receipts for deposit into a special fund. The race track operator was entitled to withdraw amounts from the fund only with the express permission of the state racing commission and for the limited purpose of repair, maintenance, and expansion of its facilities. At the end of three years, any amount remaining in the fund reverted to the state. “It was taxpayer’s own receipts from its own operations, of which it was temporarily deprived of enjoyment but as to which it later realized enjoyment to the extent that the fund was utilized.” Id. at 370. The court noted that little or no money placed in the fund had ever reverted to the state. The court held that the amounts the operator received and transferred to the fund were not income until the racing commission actually credited the amounts to the operator.
The Field also cites Mutual Telephone Co., supra, for this position. There, a telephone utility was authorized by its regulatory commission to collect additional funds from customers in 1941 and 1942 through increased rates in order to curtail demand. The commission indicated that the additional funds were not being received as additional revenue or collected for the taxpayer's benefit, but rather the amounts were paid into a special account over which the commission held ultimate control until 1949. The court held that the amounts were not includible in taxpayer's gross income in 1941 and 1942, but were includible in gross income when made available to the taxpayer in 1949.
We note that in Maryland Jockey Club, the taxpayer was entitled to withdraw amounts from the fund only with the express permission of the state racing commission. In Taxpayer from having to include the full amount of such gain proceeds in its gross income in the year of sale.
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Mutual Telephone Co., the additional amounts were paid into a special account over which the commission held ultimate control. In the instant case, however, the facts do not indicate that the Taxpayer must obtain the Commission’s permission in order to withdraw funds to pay its operating NUG obligations. Nor do the facts indicate that the Commission has ultimate control over the NUG Trusts. Rather, the facts only specify the investment parameters of the NUG Trust and the accounting or bookkeeping requirements of the Taxpayer in maintaining the trusts. The fact that the earnings on the funds in the NUG Trusts are also applied to Taxpayer’s stranded costs do not constitute a substantial restriction, but instead results in an additional source of income out of which the Taxpayer may satisfy its NUG obligations. As noted previously, the use of the trusts to hold the funds was not mandated by the Act. Consequently, we believe that these cases are distinguishable from the present case.
Additionally, we do not view the Taxpayer’s and the Commission’s agreement, prior to the actual sale of the assets, that the Taxpayer would place a portion of the gain proceeds in trust as a substantial restriction on the Taxpayer’s access to the funds.
With respect to this point, we note that the economic benefit doctrine, developed in case law, provides that if a promise to pay an amount is funded and secured by the payor, and the payee is not required to do anything other than wait for the payments, an economic benefit is considered to have been conferred on the payee and the amount of such benefit is considered to have been received. See, e.g., Sproull v. Commissioner, 16 T.C. 244 (1951), aff’d., F.2d 541 (6th Cir. 1952). Further, if a taxpayer is required to deposit receipts (otherwise taxable) into a trust, the receipts are taxable upon receipt notwithstanding the trust if the funds in the trust must be paid to taxpayer or used for taxpayer’s benefit. See, e.g., Firetag v. Commissioner, T.C. Memo. 1999-355, aff’d by unpublished opinion, 232 F.3d 887 (4th Cir. 2000), and Johnson v. Commissioner, 108 T.C. 448 (1997), aff’d in part and rev’d in part (on another issue), 184 F.3d 786 (8th Cir.
1999). The key is that the taxpayer had a fixed right to the proceeds since ultimately they would inure to his benefit.
In the instant case, the Settlement, which was incorporated into the Final Order, provides that the primary purpose of the separate NUG Trusts was to ensure an actual source of cash from which the Taxpayer can pay NUG obligations under existing NUG contracts. Therefore, the funds in the NUG Trusts inure to the benefit of the Taxpayer by being earmarked for use in the payment of the Taxpayer’s existing operating NUG obligations. Under the above line of cases, the fact that the gain proceeds were placed into the NUG Trusts as a source from which to pay Taxpayer’s NUG obligations does not preclude such funds from immediate inclusion in Taxpayer’s gross income. The use of the NUG Trusts was not required by the Act. In addition, the submissions do not cite to any court cases or revenue rulings that treat proceeds from the sale of assets as overrecovery situations involving regulated utilities.
Accordingly, the gain proceeds from the sale of Taxpayer’s generation plants are within the meaning of gross income under § 61, were received by Taxpayer under a claim of TAM-135331-05 13 right, and are includible in Taxpayer’s gross income in the year of the sale of the generation assets.
CAVEAT(S):
A copy of this technical advice memorandum is to be given to the taxpayer(s). Section 6110(k)(3) of the Code provides that it may not be used or cited as precedent.