The Arizona Public Service Company (APS), a utility company that supplies power to most of Arizona, and several of its wholesale customers, appeal from two rate-making decisions of the Federal Energy Regulatory Commission (FERC). APS had proposed a rate increase that the wholesale customers opposed. APS and the wholesale customers now challenge various aspects of the FERC’s resolution of the rate-making dispute.
FACTS
A. The Parties
APS is an investor-owned public utility that sells wholesale and retail electricity to customers throughout Arizona. Its wholesale sales are regulated by the FERC under the Federal Power Act, 16 U.S.C. §§ 824 et seq. The remaining petitioners are all wholesale purchasers of electricity from APS. Papago Tribal Utility Authority (Papago) provides electrical service for the Papago Indian reservation located near Tucson, Arizona. Arizona Power Authority (APA) is a state agency that provides electricity to municipalities and other jurisdictions within Arizona. The districts primarily provide electricity for pumping water used in irrigation.
B. The Proceedings
On December 18, 1980, APS filed proposed wholesale rate increases with the FERC. The proposed increases amounted *1058to $14.7 million, or 25.5 percent. Papago, APA, and the districts challenged the proposed rate increases and moved to intervene in the matter.
On February 27, 1981, the FERC issued an order allowing the rate increases to take effect as of March 2, 1981, subject to APS’ promise to refund any amounts collected under rates that proved to be excessive. The FERC granted motions of Papago, APA, and the districts to intervene, and set the matter for a hearing before an administrative law judge (AU).
The hearing (“phase I”) was convened on November 17, 1981, and concluded a month later. Among the issues included were whether the FERC’s “test year” procedures should be modified to reflect certain planned sales of power by APS, whether the savings from certain of APS’ investment tax credits should be passed on to ratepayers, and whether ratepayers should be required to pay for the construction of Palo Verde nuclear power plant.
On March 8, 1982, before the AU. had disposed of the case, the FERC’s Staff Counsel moved to reopen the matter for the purpose of exploring ratemaking issues arising out of a sale of tax benefits by APS. The transaction was structured so that APS sold its newly completed Cholla 4 steam electric generating station to General Electric Company (General Electric) for a $50.6 million cash downpayment and a note that provided for installment payments by General Electric. General Electric immediately leased Cholla 4 back to APS, the lease payments equaling the installment payments. The net result was that General Electric paid $50.6 million for the tax benefits of owning Cholla 4, pursuant to the Economic Recovery Tax Act of 1981 (ERTA), while APS retained use and control of the facility. The AU ordered that a second hearing be held (“phase II”) to consider the Cholla 4 transaction. The phase II hearing was held on May 17-21, 1982.
On October 15, 1982, the AU issued the decision in phase I. On February 25, 1983, the AU issued the decision in phase II. The FERC affirmed both decisions, and the parties timely appealed to this court, where their appeals were consolidated.
DISCUSSION
I. STANDARD OF REVIEW
In a complex ratemaking case such as the present one, we defer to the FERC’s substantial expertise. See Gainesville Utilities Dep’t. v. Florida Power Corp., 402 U.S. 515, 528, 91 S.Ct. 1592, 1599, 29 L.Ed.2d 74 (1971). The findings of the Commission as to the facts, if supported by substantial evidence, shall be conclusive. 16 U.S.C. § 8251 (1982); Cities of Riverside and Colton v. FERC, 765 F.2d 1434, 1438 (9th Cir.1985). Moreover, “the breadth and complexity of the Commission’s responsibilities demand that it be given every reasonable opportunity to formulate methods of regulation appropriate for the solution of its intensely practical difficulties. * * * [Therefore * * * the Commission’s orders may not be overturned if they produce ‘no arbitrary result.’ ” Nevada Power Co. v. FPC, 589 F.2d 1002, 1005-06 (9th Cir.1979) (quoting Permian Basin Area Rate Cases, 390 U.S. 747, 790-92, 88 S.Ct. 1344, 1372-73, 20 L.Ed.2d 312 (1968)); see Cities of Riverside and Colton, 765 F.2d at 1438. “If the total effect of the rate order cannot be said to be unjust and unreasonable, judicial inquiry under the Act is at an end. * * * [T]he Commission’s order * * * is the product of expert judgment which carries a presumption of validity.” Nevada Power, 589 F.2d at 1006 (quoting FPC v. Hope Natural Gas Co., 320 U.S. 591, 602, 64 S.Ct. 281, 287, 88 L.Ed. 333 (1944)). In reviewing a Commission order, the court has three responsibilities.
First, it must determine whether the Commission’s order, viewed in light of the relevant facts and of the Commission’s broad regulatory duties, abused or exceeded its authority. Second, the court must examine the manner in which the Commission has employed the methods of regulation which it has itself selected, and must decide whether each of the order’s essential elements is sup*1059ported by substantial evidence. Third, the court must determine whether the order may reasonably be expected to maintain financial integrity, attract necessary capital, and fairly compensate investors for the risks they have assumed, and yet provide appropriate protection to the relevant public interests * * * * The court’s responsibility is not to supplant the Commission’s balance of these interests with one more nearly to its liking, but instead to assure itself that the Commission has given reasoned consideration to each of the pertinent factors.
Permian Basin Area Rate Cases, 390 U.S. 747, 791-92, 88 S.Ct. 1344, 1372-73, 20 L.Ed.2d 312 (1968).
II. PHASE I OF THE PROCEEDINGS
A. Application of the Test Year Procedure.
When a regulated utility proposes a wholesale rate increase, the FERC requires the utility to submit cost of service data for two time periods. Period I contains actual data for the most recent twelve months. Period II, the test year, contains estimated cost of service data for any twelve consecutive months beginning after the end of Period I but no later than the proposed effective date' of the rate filing. 18 C.F.R. § 35.13 (1984); Indiana Municipal Electric Association v. FERC, 629 F.2d 480, 481 (7th Cir.1980). The FERC adopted the test year approach because the historic test period exclusively used in the past was too rigid to result in just and reasonable rates. Id. If, as is often the case, the actual data for the test year becomes available during the course of ratemaking proceedings, the FERC need not adjust the test year estimates. Boroughs of Ellwood City v. FERC, 731 F.2d 959, 966 (D.C.Cir.1984). Rather, the FERC determines whether the test year estimates were reasonable when they were made. If so, the FERC will follow the estimates unless they are substantially in error and would yield unreasonable results. Id.; Indiana Municipal Electric Association, 629 F.2d at 483-85.
In December, 1980, when APS filed its proposed rate increases with the FERC, it submitted projected financial data for 1981 as its test year estimates. Those test year estimates did not include revenues that APS was planning to receive in the future from post-test year layoff sales of power to third parties. Papago challenges the FERC’s refusal to provide an automatic rate adjustment of APS’ rates for revenues received from layoff sales which occur after the test year. Papago contends that APS will be paid twice for the same capacity if no such provision is made because the test year estimates included the costs associated with the capacity that will be sold to third party purchasers in the future.
The AU found that the post-test year layoff sales should not be considered part of this case, and ruled that the issue was moot. Rather, the AU found that the issue should be reserved for separate proceedings arising out of a rate increase filed by APS on April 29,1982. In affirming the AU’s decision, the Commission held that whether or not the issue was moot, the facts were not egregious enough to warrant a departure from its “longstanding policy” of determining rates based on test year estimates. Indeed, the Commission stated that it might not be fair to require a credit for post-test year layoff sales without considering possible post-test year cost increases.
As the Commission recognized, Papago’s concern that APS would be paid twice for the same capacity has some merit. This does not mean, however, that the Commission should have adjusted the test year estimates. The Commission concedes and reviewing courts admit that the test year approach presupposes certain inexactness. See, e.g., Cities of Batavia, etc. v. FERC, 672 F.2d 64, 74 (D.C.Cir.1982). “The Commission rightly does not require that history prove the accuracy of the utilities’ estimates * * Indiana & Michigan Municipal District v. FERC, 659 F.2d 1193, 1198 (D.C.Cir.1981). It “is justified in setting a rather high threshold for parties seeking to adjust test year data * * *1060Boroughs of Ellwood City, 731 F.2d at 967. It did not abuse its discretion in this case in refusing to adjust the test year estimates. The estimates were reasonable when made because APS did not plan to receive, nor did it receive, revenues from these sales during the test year. The fact that APS will receive these revenues in the future is not sufficient to establish that the estimates were “substantially in error” and would “yield unreasonable results.” See id. at 966. Therefore the Commission’s refusal to adjust the test year estimates for post test year layoff sales is affirmed.
B. APS’ Investment in Palo Verde
Papago contends that the FERC erred in approving a rate increase that was based in part on the cost of financing construction of the Palo Verde nuclear power plant. It argues that APS’ investment in the plant is unnecessary because Palo Verde will not be “used and useful” in providing service and because energy conservation is a much less expensive alternative to building the plant. Because Papa-go’s arguments in this regard are almost entirely factual, we consider only whether the FERC’s findings are supported by substantial evidence. See 16 U.S.C. § 8251 (1982); Cities of Riverside and Colton v. FERC, 765 F.2d at 1438.
The AU rejected APS’ initial contention that the decision to construct Palo Verde was beyond FERC review. The AU found that even though the plant was not in service and hence was not included in the rate base during the test year, its construction would affect current ratepayers because the utility sells securities to finance the construction, and the FERC considers APS’ need for capital in establishing its rate of return allowance. The AU then thoroughly analyzed Papago’s arguments and evidence relating to Palo Verde, and the arguments and evidence offered by APS in rebuttal. The AU’s rejection of Papago’s position was affirmed without comment by the FERC.
The test for determining whether an investment may be included in a utility’s rate base is whether it is “used and useful” in providing service to current customers. Anaheim, Riverside, Banning, Colton, and Azusa, California v. FERC, 669 F.2d 799, 808 (D.C.Cir.1981). The AU summarized Papago’s evidence that rates would be lower without Palo Verde construction costs, and that there was untapped potential for energy conservation in APS’ service area. Based on the record, however, the AU concluded that the Palo Verde plant will be used and useful to meet APS’ service requirements. The AU found that the evidence
stopped considerably short of a convincing showing that the capacity and energy of the Palo Verde plant would not be required to meet the demands in APS’ service territory. By no stretch of the imagination did PTUA make out a case showing that the utility’s participation in the construction of the Palo Verde plant was the result of imprudent judgment on the part of its management.
Finding no evidence that the financing of the Palo Verde plant was erroneous,. the AU rejected Papago’s claim that the return allowance should be reduced to eliminate the effects of APS’ requirements for capital to support the plant. Although Pa-pago urges us to reconsider the AU’s conclusion, substantial evidence in the record supports it.
The AU also carefully analyzed the contention that APS’ rate increase be reduced or denied because APS has not adequately investigated conservation measures as an alternative to new plant construction. He concluded that Papago failed to prove that APS had acted imprudently in failing to implement a program of conservation incentives that, prior to the hearing, “lay dormant in the breast of [Papago’s witness].” The AU found that APS’ actions were not imprudent because they were consistent with the performance of other similarly situated utilities. In addition, the AU found that APS had implemented “a large number of innovative and constructive steps to spur conservation of electric energy in its service area.” Because ample *1061evidence in the record supports the AU’s findings, we will not disturb them on appeal.
C. Normalization of Investment Tax Credits.
After APS filed the Notice of Rate Change in December of 1980 (Docket ER 81-179) that initiated this case, Congress passed' the Economic Recovery Tax Act which requires, among other things, that public utilities use the normalization method of accounting for investment tax credits (ITCs). See S.Rep. No. 144, 97th Cong., 1st Sess. 57, reprinted in 1981 U.S.Code Cong. & Ad.News 161-62. ERTA contained a transitional rule applicable to utilities which had previously flowed through ITCs. Those utilities would not lose the right to use ITCs on their tax returns if they secured the right to normalize in the first rate order issued with respect to it after the date of enactment of ERTA (August 13, 1981) and such rate order is issued before January 1, 1983. Economic Recovery Tax Act of 1981, Pub.L. No. 97-34, 95 Stat. 226-227, reprinted in Internal Revenue Acts, 1980-81, at 346-47.
The issue here is when the normalization method should be adopted. In its December 30, 1982 order the Commission initially considered this issue, and rejected APS’ position that ERTA requires that normalization be adopted in this proceeding. Use of the normalization method in APS’ April, 1982 rate filing (Docket ER 82-481) satisfied ERTA’s requirements. The Commission decided this issue without prejudice to final determination of this matter in its Phase I opinion. “Order Determining Cost of Service For Purpose of ERTA Compliance,” 21 FERC U 61,384 (1982).
The AU considered the issue in Phase I of the proceedings. He agreed with the Commission’s preliminary conclusion that ERTA does not require the use of the normalization method in this proceeding.
The Commission, in Opinion No. 177, 23 FERC H 61,419 (1983), reversed the AU on this point. It concluded that normalization “is consistent with Commission policy on this issue, it conforms to Commission Order Nos. 144 and 144-A, and it will not result in rates higher than the overall rate level sought by APS in this proceeding.”
Papago appeals that decision. It argues, first, that ERTA does not require utilities to normalize ITC immediately. The Commission’s decision to normalize ITCs in this proceeding is within its discretion, however, and is consistent with both Congress’s goals and Commission policy. See “General Explanation of the Economic Recovery Tax Act of 1981,” Staff of the Joint Committee on Taxation, at 101, (December 29, 1981), reprinted in Internal Revenue Acts, 1980-81, at 1475-76; “Policy Statement Regarding Income Tax Normalization Under the Economic Recovery Tax Act of 1981,” 20 FERC U 61,451 (1982).
Papago next argues that the Commission’s order contradicts its earlier December 30, 1982 order on the same issue. This argument fails, however, because that order was made without prejudice to its formal determination in this proceeding.
Papago also claims that the ERTA normalization requirement is irrelevant here because APS. sold all of its ITCs to General Electric in the Cholla No. 4 safe-harbor transaction. The record shows, however, that APS has post-1980 recovery property other than the Cholla No. 4 generating unit that was the subject of the safe-harbor transaction. Thus, Papago’s fails on this issue as well.
Finally, Papago argues that ITCs are tax saving, rather than tax deferral, items and thus are not properly subject to the normalization provision of ERTA. This argument is technically correct: the Commission in fact permitted “ratable flow-through” of ITCs, rather than normalization.1 Normali*1062zation is used as a synonym, however, and is clearly required by the Congress in ERTA. See ERTA, Pub.L. No. 97-34, 95 Stat. 226-227, reprinted in Internal Revenue Acts, 1980-81, at 346-47.
III. PHASE II OF THE PROCEEDINGS; PROPER TREATMENT OF THE $50.6 MILLION PROCEEDS OF THE CHOLLA NO. 4 SAFE HARBOR TRANSACTION.
As indicated above, in 1981, APS entered into a “safe harbor” leasing agreement with General Electric, under which APS transferred to General Electric the right to take depreciation deductions under the Accelerated Cost Recovery System (ACRS) and to use investment tax credits (ITCs) stemming from APS’ investment in Cholla No. 4. Under the terms of the agreement, General Electric paid APS $50.6 million in cash at the time the contract was executed and promised to pay the balance of the “purchase price” of $250 million (an amount equal to APS’ adjusted basis of the Cholla No. 4 unit for tax purposes) in installments over the 42-year life of the lease. The periodic payments were exactly offset by the amount of the rental payments that APS was obligated to make for the lease-back of the unit. APS’ rent payments are fully tax deductible, and only the interest portion of the installment payments from General Electric is includable in income. At the end of the 42-year term of the lease, ownership of the unit vests in APS.
Under the “safe harbor” leasing provision of section 201(a) of ERTA, I.R.C. § 168(f)(8),
a transaction will be characterized as a lease for the purpose of allowing investment credits and capital cost recovery allowances to the nominal lessor. Lessors will be able to receive cost recovery allowances and investment tax credits with respect to qualified leased property, while it is expected that lessees will receive a very significant portion of the benefit of these tax advantages through reduced rental charges for the property (in the case of finance leases) or cash payments and/or reduced rental charges in the case of sale-leaseback transactions.
S.Rep. No. 144, 97th Cong., 1st Sess. 62 (1981), reprinted in 1981 U.S.Code Cong. & Ad.News 167. Thus, ERTA provided that APS’ transaction with General Electric be characterized as a lease. The issue here is how to treat this transaction for rate-making purposes.
Under public utility cost of service ratemaking principles, taxes are one element of the company’s cost of service. Public Systems v. FERC, 709 F.2d 73, 75 (D.C.Cir.1983). Because ratepayers are being charged for the utility’s tax costs, the ratepayers receive the tax benefits associated with those expenses. Id. at 76. Thus, the tax benefits which APS sold would have inured to the benefit of APS’ ratepayers. Because the ratepayers would have received these tax benefits over time, there is significant dispute among the parties about the present value of this loss. In addition, the company asserted that any loss was offset by gains attributable to the transaction.
The AU found that the net present value of the tax benefits transferred by APS, in terms of the increase in its cost-of-service tax expense, was $47 million, and that the amount the ratepayers lost in reduced rates was $123.5 million. In determining how to compensate the ratepayers for their loss, the AU carefully considered the proposals of the parties. He rejected the parties’ proposals to apportion the proceeds between an amount paid for the ACRS deductions and a separate amount paid for the ITCs because the proposals were grounded on the legal fiction that a separate sum was paid for each. Rather he concluded that the $50.6 million APS received from General Electric constituted a negotiated price for a package of nonseverable tax benefits. Because the AU found that the transaction was not an im*1063prudent one for APS to enter into, he refused to punish the utility by requiring it to reduce its cost of service by some larger amount than it actually realized from the sale in an attempt to make whole the ratepayers.
The AU considered and rejected simply disregarding the tax benefit transfer transaction and prescribing APS’ rates as if it had never occurred, preferring instead to recognize the realities of the transaction and not to adopt the fictitious premises that the tax benefits remain in APS’ hands. He decided, therefore, that the entire amount of the proceeds ($50.6 million) should be amortized as a credit to the cost of service over the economic life of Cholla No. 4, and that the unamortized balance of the proceeds should be deducted from the utility’s rate base.
In Opinion No. 193, 25 FERC 1161,092 (1983), the Commission affirmed the AU’s decision with one exception. The AU had ordered that the proceeds be amortized over the entire twelve months of the test year. The Commission ordered that the amortization of the $50.6 million be synchronized with the Cholla No. 4 in-service date so that the proceeds would be amortized as of June, 1981, when Cholla No. 4 was placed in service. The Commission’s order on rehearing, Opinion No. 193-A, 25 FERC 1161,393 (1983), rejected APS’ argument that the AU’s treatment of the $50.6 million violated ERTA and again affirmed the AU’s decision.
APS now challenges the AU’s decision on several grounds. First, it argues that the Commission erred in adjusting its test year estimates to take the Cholla 4 transaction into account. Because the test year estimates were prepared prior to the enact-, ment of ERTA, all of the parties agree that the test year estimates were reasonable when made. See Villages of Chatham, etc. v. FERC, 662 F.2d 23, 34 (D.C.Cir.1981). ERTA was enacted and the tax benefits were sold during the test year. The issue is whether “subsequent events indicate that to use [the estimate] as a basis for future projections would yield unreasonable results.” Indiana & Michigan Municipal Distributors v. FERC, 659 F.2d 1193, 1198 (D.C.Cir.1981) (quoting Indiana Municipal Electric Association v. FERC, 629 F.2d 480, 485 (7th Cir.1980)). The AU found that because the Cholla 4 transaction took place pursuant to an unforeseen change in the tax laws, it warranted an adjustment to the test year estimates. The FERC affirmed.
APS contends that the decisions of the AU and FERC indicate that the FERC did not find the effect of the Cholla 4 transaction to be substantial, and thus the FERC erred in adjusting the test year estimates. The FERC’s decision, however, expressly stated that the FERC “has made exceptions to its traditional adherence to the test-year concept in cases where there are known and measureable changes of a substantial nature. That is the case here.” Opinion No. 193, 25 FERC 11 61,092 at 61,-308 (footnote omitted). The FERC also expressly rejected APS’ contention that the $50.6 million Cholla 4 transaction had a de minimis effect on revenue. Id. In light of the latitude courts have given the Commission to determine whether to adopt or reject actual data from the test year, see Indiana & Michigan Municipal Distributors, 659 F.2d at 1197-98; Indiana Municipal Electric Association, 629 F.2d at 481, we find that the FERC did not abuse its discretion in adjusting the test year estimates based on an unforeseen transaction of such magnitude. See Distrigas of Mass. Corp. v. FERC, 737 F.2d 1208, 1220 (1st Cir.1984) (FERC not required to use test year figures when later information reveals estimates based on those figures likely to be seriously in error).
APS next argues that the AU’s computation of the loss incurred by the ratepayers as a result of the safe harbor transaction was erroneous. APS argues that the AU’s findings are not supported by substantial evidence and must be reversed. APS’ argument ignores the Commission’s conclusion that it need not rely upon the AU’s calculation of the precise amount of extra costs the ratepayers will incur be*1064cause it adjusted the cost-of-service only by the amount of the proceeds. Opinion No. 193, 25 FERC H 61,092 at 61,309. Thus, the evidence need only support the Commission’s position that the ratepayers’ loss amounted to at least $50.6 million. APS cannot dispute that figure because it has conceded that the net present value of costs the ratepayers will incur is $82.6 million.
Third, APS argues that the AU’s treatment of the proceeds from the safe-harbor transaction violates I.R.C. § 168(f)(8) as amended by the Technical Corrections Act of 1982. The Act amended § 168(f)(8)(D) as follows: “[ujnder regulations prescribed by the [Treasury] Secretary, public utility property shall not be treated as qualified leased property unless the requirements of rules similar to the rules of subsection (e)(3) of this section and section 46(f) are met with respect, to such property.” Pub.L. No. 97-448, 96 Stat. 2365, 2369 (1982), reprinted in Internal Revenue Acts, 1982, at 350.
Sections 168(e)(3) and 46(f) require utilities to use the normalization method of accounting2 for ACRS depreciation deductions and ITCs, respectively. Thus, APS argues that the proceeds of the safe-harbor transaction must be apportioned between those attributable to ITCs and ACRS and that each portion of the proceeds must be treated differently from the method chosen by the AU. The Commission in its order on rehearing, Opinion No. 193-A, 25 FERC 1161,393 (1983), addressed this contention. It rejected APS’ interpretation of the amendment and found the amendment’s meaning ambiguous. Id. at 61,871. The Commission interpreted the amendment as applying to the ACRS deductions and ITCs themselves and not to the proceeds of the sale of the tax benefits. It stated, however, that if the Treasury Department issued regulations pursuant to this amendment which indicate that its treatment is contrary to the tax laws it will reconsider its decision. Id.
We agree with the Commission that the amendment’s meaning is unclear; we have found no subsequent authority clarifying its meaning. This is not surprising because the safe harbor leasing provision was short-lived: it was repealed the year after it was enacted. Section 209 of the Tax Equity and Fiscal Responsibility Act of 1982, Pub.L. No. 97-248, 96 Stat. 324, 442, reprinted in Internal Revenue Acts, 1982, at 41. Because the Commission’s decision is supported by clearly articulated reasons, we cannot say that it abused its discretion in rejecting APS’ contentions. See Ohio Power Co. v. FERC, 668 F.2d 880, 886 (6th Cir.1982) (on other than factual issues, court reviews to determine whether the order is arbitrary or capricious, whether there has been an abuse of discretion, or whether rational basis exists for a conclusion).
The Commission conceded that the apportionment of the proceeds sought by APS would have been preferable because it would have permitted investors and ratepayers to enjoy the benefits to which they would have been entitled if APS had used the tax benefits itself. The Commission found this goal unattainable, however, because of the significant problems with the apportionment proposals on the record, and found the ALJ’s proposal superior to any of the others. In the absence of a clear *1065congressional directive to the contrary, we will not reject the Commission’s resolution of this issue. See FPC v. United Gas Pipeline Co., 386 U.S. 237, 246, 87 S.Ct. 1003, 1008, 18 L.Ed.2d 18 (1967).
APS’ last challenge to the Phase II decision is that the Commission erred in synchronizing the ratemaking treatment of the proceeds with the in-service date of Cholla No. 4. APS argues that synchronization is improper because it assumes that APS had use of the sales proceeds as of the in-service date in June, 1981, rather than almost six months later when they were actually received in November, 1981. Because the in-service date is the date at which the ratepayers were responsible for paying the costs attributable to the investment and the date at which APS earned the right to receive the tax benefits, the Commission did not abuse its discretion in ordering that the proceeds be amortized as of that date.
APA and the districts also challenge the synchronization of the proceeds. They contend, however, that the proceeds should have been amortized over the full year, rather than one-half year as required by the Commission. The Commission’s explanation for adjusting the test year estimates based on one-half year’s amortization is reasonable, however; thus it does not constitute an abuse of discretion. See Ohio Power, 668 F.2d at 886.
Papago also challenges the Commission’s ratemaking treatment of the proceeds of the Cholla 4 transaction. It argues in reliance upon Midwestern Gas Transmission Co. v. FPC, 388 F.2d 444 (7th Cir.), cert. denied, 392 U.S. 928, 88 S.Ct. 2286, 20 L.Ed.2d 1386 (1968), that the Commission erred in limiting the rate adjustment to the dollar value of the sales proceeds rather than the full value of the tax benefits to the ratepayers. In Midwestern, the utility had reverted from liberalized depreciation to straight-line when the FPC required it to flow-through the tax savings resulting from use of the former method to its ratepayers. The court found that management had chosen “the one method certain to result in maximum tax costs to themselves, with resulting maximum rates to the consumers,” id. at 448, and that the resulting increased tax cost was not a “reasonable and prudent business expense” which the ratepayers could be required to bear. Id.
Papago contends that APS’ sale of the tax benefits was imprudent under Midwestern because there was no legitimate business purpose for the sale. Papago claims that the sale would have been proper only if APS could not have used the ACRS deductions and ITCs to reduce its taxes in the future. Papago is unable to overcome the AU’s finding that the transaction was not imprudent because one of Congress’ major purposes in enacting the safe-harbor leasing provision was to make it perfectly legal for corporations, including APS, to transfer future potential benefits into current income. See “General Explanation of the Economic Recovery Tax Act of 1981,” Staff of the Joint Committee on Taxation, at 103 (December 29, 1981), reprinted in Internal Revenue Acts, 1980-81, at 1478. We therefore decline to disturb the AU’s exercise of his sound discretion in concluding that APS acted prudently in selling its tax benefits to General Electric.
The orders of the Commission in this case are AFFIRMED.
. To normalize or ratably flow-through ITCs is to evenly spread the credit to the utility’s present and future ratepayers over the useful life of the property giving rise to the credit. To flow-through the ITCs is to give an immediate benefit of the total ITC to the current ratepayers. Arizona Public Service Co., Docket No. ER-*106282-481-000, 25 FERC ff 63,025 at 65,061 (1983), aff’d, 27 FERC If 61,185 (1984).
. Normalization of accelerated depreciation methods means that the rates charged to utility customers do not reflect a ratemaking allowance for Federal income taxes based on the use of a depreciation method more accelerated than the depreciation method used to determine the ratemaking allowance for depreciation. It results in an actual Federal income tax expense that was less than the ratemaking tax allowance in the early years of an asset's useful life and more than the ratemaking allowance in the later years of an asset’s useful life. These "deferred taxes” could be viewed as an interest-free loan to the utility. General Explanation of the Economic Recovery Tax Act of 1981, prepared by the Joint Committee on Taxation, reprinted in Internal Revenue Acts, 1980-1981, at 1445.
The use of accelerated depreciation in rate-making to compute the allowance for federal income taxes is known as “flow-through” accounting, because current tax reductions are immediately reflected in lower rates to customers. Id. at 1446.