#### FORT PIERCE UTILITIES AUTHORITY OF the CITY OF FORT PIERCE, Lake Worth Utilities Authority, and the Cities of Homestead and Starke, Florida, Petitioners, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Sebring Utilities Commission, et al., Florida Power Corporation, Florida Power & Light Company, Intervenors.

No. 83-1286.

United States Court of Appeals, District of Columbia Circuit.

Argued Jan. 5, 1984.

Decided March 16, 1984.

*779Robert A. Jablon, Washington, D.C., with whom Marc R. Poirier and Joseph L. Van Eaton, Washington, D.C., were on brief, for petitioners.

Joel Cockrell, Atty., F.E.R.C., Washington, D.C., for respondent. Stephen R. Melton, Acting General Counsel, Jerome M. Feit, Sol., and Thomas E. Hirsch, III, Atty., F.E.R.C., Washington, D.C., were on brief, for respondent. Barbara J. Weller, Atty., F.E.R.C., Washington, D.C., also entered an appearance for respondent.

Robert T. Hall, III, Washington, D.C., with whom Richard M. Merriman and Floyd L. Norton, IV, Washington, D.C., were on brief, for intervenor, Florida Power and Light Company.

George F. Bruder, Washington, D.C., was on brief for intervenor, Florida Power Corporation. James E. Hickey, Jr., Washington, D.C., also entered an appearance for Florida Power Corporation.

Robert A. Jablon, Washington, D.C., entered an appearance for intervenors, Sebring Utilities Commission, et al.

Before TAMM and WALD, Circuit Judges, and MacKINNON, Senior Circuit Judge.

Opinion for the Court filed by Circuit Judge WALD.

Opinion concurring in part and dissenting in part filed by Senior Circuit Judge MacKINNON.

WALD, Circuit Judge:

In this case, several Florida municipal electric utilities1 (“Florida Cities”) seek direct review of an order of the Federal Energy Regulatory Commission (“FERC" or “the Commission”) establishing transmission rates for Florida Power & Light Co. (“FP & L”). *Florida Power & Light Co.,*21 FERC 1161,070 (1982), *rehearing denied,*22 FERC 1161,012 (1983).2 The municipal customers claim that these rates are excessive and discriminatory in violation of the Federal Power Act, 16 U.S.C. § 824d, on two independent grounds: First, they claim that FERC’s failure to order FP & L to file joint rates with another large investor-owned utility, Florida Power Corporation (“FPC”), results in unwarranted double transmission rates for wheeling transactions that cross through the transmission systems of both FP & L and FPC. Second, the municipalities claim that FERC improperly allowed FP & L to include in its short-term transmission rates “capacity costs”— *i.e.,*costs associated with the construction *780and maintenance of transmission facilities with sufficient capacity to serve the utility’s customers at peak power loads. For the reasons stated below we uphold the Commission’s refusal to order joint transmission rates, but we remand for further consideration its decision to permit the inclusion of capacity costs in the rate base for all classes of transmission service at issue.

I. Background

FP & L, the largest electric utility in Florida, sells power and transmission services to retail and wholesale customers. Its retail service area, over which its transmission lines extend, covers virtually the entire Atlantic coast area from the Georgia border to Miami and the Gulf coast from Sarasota southward. FP & L, together with FPC, serve practically the entire Florida peninsula; the Tampa area is served by another investor-owned utility, Tampa Electric. Within the service areas of the two largest privately-owned utilities lie numerous small municipal and cooperatively-owned electric utilities, including Florida Cities, which serve their own customers.

The transmission system of each utility is directly connected with that of one or more adjoining utilities, and thus indirectly connected with every other utility in peninsular Florida, enabling FP & L, FPC, Florida Cities and others to create a regional market for the exchange of excess generating capacity. Under a set of “interchange agreements,” each utility can buy electricity generated by any other utility for periods ranging from one hour to three years to supplement power during generator emergencies, equipment maintenance or any time when the buyer’s incremental generation costs are, for whatever reason, higher than the seller’s.3 These interchange agreements improve the reliability and efficiency of the entire peninsular electric system, and permit each utility to maintain less excess capacity than it would otherwise need to serve its customers’ maximum needs.4

When one utility buys power under an interchange agreement from a utility with which its transmission lines are directly connected, it pays no transmission charge.5 However, when a utility buys from another with which it is not directly connected, it must obtain transmission or “wheeling” services and pay for those services. In practice this affects primarily the small utilities such as Florida Cities because the transmission systems of FP & L and FPC are each directly connected with the other, with Tampa Electric, and with numerous municipal customers; they seldom have the need to purchase power from utilities with which they are not directly connected.

FP & L filed with FERC a set of transmission service agreements (TSAs) setting out the terms under which it would offer wheeling service to a utility purchasing power under an interchange agreement from another utility, delivery of which required the use of FP & L’s transmission network.6 Florida Cities protested, argu*781ing that FP & L’s rates, together with corresponding rates filed by FPC, would result in excessive and discriminatory combined charges for transactions that required wheeling by both FP & L and FPC. Cities argued that these transactions should be viewed as a single transmission on the combined FP & L/FPC network performed in part by each utility, and for which each should receive part of a single “joint rate.” In support of this proposal, Cities presented evidence of a high degree of coordination and integration among peninsular Florida utilities, and especially between FP & L and FPC.

Cities argued in addition that at least as to transmission rates for emergency service for periods no longer than 72 hours (TA service) and “energy exchanges” for periods of one hour (TC service), the applicable rates should not include “capacity” or “demand-related” costs. They argued that because the transmitting utility could simply decline to enter into TSAs of such short duration whenever it did not anticipate having enough excess transmitting capacity, transmission under TA and TC service agreements did not require the planning, construction and maintenance of any additional capacity and should not be assigned any of the associated capacity costs. FERC rejected both arguments and, with minor modifications, approved FP & L’s rates as just and reasonable, as required by the Federal Power Act. Cities appeal from both the refusal to impose joint rates and the inclusion of capacity costs.

II. Joint Rates

In *Richmond Power & Light v. FERC,*574 F.2d 610 (D.C.Cir.1978), we upheld FERC’s rejection of a municipal electric utility’s proposal of joint rates — or “through rates” — for wheeling transactions crossing two or more electrical systems. We held that “the Commission’s failure to establish through rates can be deemed arbitrary only if the individual rates were unjustly or unreasonably high and, as well, the utilities had a duty to wheel.” *Id.*at 619. Florida Cities do not claim that these conditions are met here. Unlike Richmond Power, they do not contend that FP & L and FPC are obligated to wheel.7 Moreover, they contend that even if the individual rates accurately reflected a proper application of accepted costing methodology,8 joint rates would be required. Cities argue that this case falls outside the scope of the test set out in *Richmond Power*because of one significant factual difference: Cities contend that FP & L and FPC have so fully integrated their transmission systems that they in fact function as a single unified network. In order to evaluate the significance of this claim, we must understand Cities’ proposal in more depth.

A. *The Problem: “Double Rates”*

Florida Cities illustrates their argument for joint transmission rates with the case of New Smyrna Beach, Florida.9 New *782Smyrna, which is located on the east side of the state in FP & L’s service area, owns four megawatts of power from the Crystal River Unit 3 nuclear plant (CR-3) constructed by FPC and located in its service area across the state. New Smyrna thus requires wheeling by both FPC and FP & L.

Under the pricing system approved here by FERC, a utility determines its transmission costs per unit of electricity by dividing the total annual costs of constructing and maintaining its entire transmission network by the load, or the amount of power on the network, at certain peak periods.10 This “rolled-in” method of calculating transmission costs, which Cities do not quarrel with, is based on the recognition that a unit of electricity does not actually travel like a railroad shipment from the point at which it enters the system to the point to which it is delivered. A transmission network functions more like a reservoir: a given amount of power enters the system at one point and a like amount is delivered at another point. The costs associated with this pair of operations do not vary with the distance between the point of entry and the point of delivery, but are based on the costs for the entire transmission network.11 The resulting transmission rate is thus called a “postage stamp” rate.

In the case of New Smyrna, FPC and FP & L each charges a “postage stamp” rate for the use of its transmission network.12 In other words, the two networks are treated like two adjoining reservoirs. The resulting transmission cost to New Smyrna is therefore roughly double the cost to a customer located, like the CR-3 unit itself, within FPC’s service area: even if the customer were twice as far away from the generating unit, it would pay only one postage stamp rate.

Cities claim that these individual rates combine to yield an excessive and discriminatory total rate. They argue that because FP & L and FPC pay no transmission charge for a “functionally similar” transmission of electricity across each other’s boundaries,13 these rates unduly disadvantage Cities in their competition with the large utilities for potential retail customers. Cities are discouraged from purchasing power from remote sources and largely cut off from the economic benefits of regional coordination, to the detriment of their customers and of competition in general.

B. *The Proposed Solution: Joint Rates*

Cities concede that because they, unlike FP & L and FPC, have not invested in their own transmission networks it is proper to impose on them a portion of FP & L's and FPC’s transmission costs. They also concede that, except for the inclusion of capacity costs discussed below, the individual *783transmission rates accurately reflect each utility’s fully allocated rolled-in costs. Furthermore, they acknowledge the general validity of the rolled-in methodology, and the resulting “postage stamp” rate.

The crux of Cities’ argument to this court is that FERC has applied the right methodology to the wrong transmission network. Cities claim that because of the very high degree of integration among utilities in peninsular Florida, and especially between FP *&*L and FPC, the appropriate transmission network is not defined by the corporate boundaries of FP & L and FPC. In the case of service like that offered New Smyrna, which requires the use of both FP & L and FPC transmission facilities, Cities argue that FP & L and FPC should each be viewed as performing only part of the full transaction. In their view, transmission rates should be based on the combined transmission costs of both FP & L and FPC over the functionally integrated network covering most of peninsular Florida. Cities would divide those combined costs by the total peak load on the combined network to arrive at the cost per unit on the network as a whole. This method would result in a single postage stamp rate that is roughly the *average*rather than the sum of the two utilities’ individual rates.14 Cities would then allocate that rate between FP & L and FPC on the basis of each utility’s proportional share of the costs of the combined transmission network.15 They argue that, notwithstanding the two-part test of *Richmond Power*not met here, FERC should be required to impose joint rates under these circumstances in order to alleviate the anomalous consequences of “postage stamp” rates for transactions like New Smyrna’s, and thus avoid transmission rates that are excessive and discriminatory.

The Commission rejected Cities’ proposal. Under that proposal, it concluded, joint rate customers would pay each utility significantly less than non-joint rate customers for the same use of the transmission network. According to FERC, in the absence of any evidence that each utility’s contribution to joint service is less costly than its ordinary wheeling service, the joint rate would be discriminatory as to the non-joint rate customers, forcing them to subsidize Cities’ rates for no justifiable reason. 21 FERC at 61,241.

C. *Analysis*

The Commission’s conclusion rests on the premise that wheeling transactions beginning and ending within the service area of a single utility do not use the adjoining utility’s transmission network, while wheeling involving two utilities uses both.16 If this premise is supported, then we agree with FERC that joint rates are not required. We would arrive at this conclusion whether we looked only at the rates charged by each utility or at the combined rates paid by the double-wheeling customer. It is not unjust, unreasonable and discriminatory for one utility to charge all its wheeling customers the same postage *784stamp rate for the same wheeling service.17 Nor is it discriminatory to require the double-wheeling customer to pay higher combined rates for a more costly combined service;18 it is simply an anomalous consequence of the proper application of the “rolled-in” methodology to these transactions.

Cities, however, appear to challenge the Commission’s premise that wheeling transactions beginning and ending within a single utility’s territory do not make use of the adjoining utility’s transmission network.19 They argue in effect that the FP & L/FPC transmission systems are not like two adjoining reservoirs, but rather like two sides of a single reservoir divided only by a line painted across the bottom, in which a “transmission” of water between any two points on the reservoir uses the entire reservoir regardless of whether those two points lie on the same or different sides of the line. If coordination between FP & L and FPC had become so extensive that the two systems operated as an integrated whole, then each utility’s customers would in fact use both transmission systems; in that case, the individual rates approved by FERC would arguably force customers paying “double rates” to subsidize the remaining customers by paying twice for a functionally identical transaction.

The Commission did not respond directly to Cities’ claim that, contrary to its basic premise, FPC and FP & L had created a unitary system on which all loads used the combined network.20 We cannot say with certainty that the two-part test of *Richmond Power*would necessarily control the resolution of such an unusual case. We find it unnecessary, however, to remand to FERC on this issue because we find that the evidence was sufficient to support its premise that the two transmission networks are not functionally merged.

A high degree of coordination involving frequent exchanges of power between adjoining utilities does not indicate that the utilities’ corporate boundaries have no functional significance.21 The New Smyr*785na transaction appears to involve two separately negotiated operations: FPC takes CR-3 power and delivers a like amount (minus transmission losses) to FP & L; then FP & L delivers a like amount to New Smyrna. 5 FERC at 65,161. In general, coordination among the peninsular utilities appears to take the form of discrete transactions undertaken when equipment maintenance, generator outages, significant disparities in incremental cost or other particular circumstances call for an exchange.22 The evidence indicates that these exchanges may be quite frequent, that the arrangements are streamlined and facilitated by a computerized broker system23 and that a buying utility pays for the transmission costs of an interconnected seller by absorbing its own costs on a reciprocal basis instead of by paying a transmission charge. But this evidence does not demonstrate that transfers of power between FPC and FP *&*L take place on any other basis than as discrete arms-length transactions between distinct business entities.24

We need not determine whether there will ever be circumstances under which two utilities have gone beyond extensive cooperation and have so completely integrated the operation of their transmission systems that any transmission by either utility makes use of the combined network. In that case, a transaction crossing corporate boundaries, like the transmission of water across a single reservoir, would be functionally identical to a transaction within corporate boundaries. Such unusual circumstances would present a stronger case that individual rates permitted overrecovery of costs and that joint rates were therefore required. But Florida Cities have not persuaded us that FP & L’s corporate boundaries are merely illusory and without functional significance in the wheeling transactions at issue. Under these circumstances we uphold FERC’s refusal to order joint rates.25

III. Capacity Costs

FERC permitted FP & L to include in its transmission rates the “rolled-in” costs of the entire transmission network, including so-called “demand” or “capacity” costs associated with constructing and maintaining the transmission capacity necessary for serving its customers’ peak demand.26 Cities argue that because service under the TSAs uses only excess capacity it cannot fairly be assigned capacity costs.

A. *The Transmission Service Agreements and Capacity Costs*

Electric utilities often distinguish between “firm” service, under which custom*786ers can demand power or transmission at any time, and “interruptible” service, which the utility is entitled to shut off at any point when there is not enough excess capacity beyond that required to guarantee the needs of the utility’s firm customers. Interruptible service is typically offered at a significant discount because the utility’s ability simply to cut off service at peak demand periods alleviates its need to plan for and finance additional capacity to offer the service.27 The Commission has recently explained in some detail why it ordinarily will not permit the allocation of “capacity costs” — costs associated with the need to construct and maintain sufficient capacity for reliable service at peak demand — to interruptible service, which does not impose capacity costs. *Kentucky Utilities Co.,*15 FERC ¶ 61,002, *rehearing denied,*15 FERC ¶ 61,222 (1981).

FP & L provides transmission service in conjunction with four interchange agreements: TA emergency service for periods up to seventy-two hours, TB capacity and energy for up to twelve months, TC energy exchanges for periods of one hour, and TD capacity and energy for twelve to thirty-six months. 12 FERC at 65,056. The wheeling rate applicable to all four agreements includes capacity costs associated with FP & L’s transmission system.28 Cities argued that because FP & L can simply refuse to enter into a transmission agreement, and indeed has done so, when it lacks the necessary excess capacity, it “need not plan or construct transmission capacity in anticipation of future interchange needs. As a corollary, interchange transactions, present or future, do not force FP & L to incur new capacity costs.” *Id.*At least as to short term TA emergency service and TC energy exchanges (one hour), FP & L could avoid service during peak demand periods simply by refusing new requests for service. Commission staff had argued that, in addition, TB service for less than a week should not be assigned capacity costs because it could be refused in anticipation of peak demand periods. *Id.*The AU, however, accepted the view of FP & L that all such services were “firm” — and thus properly assigned capacity costs — because “each time they commit to transmit for a period requested by the transmission customer, they commit to provide firm transmission.” 12 FERC at 66,056.

The Commission disagreed with the AU’s nomenclature:

> Because all four of the services are offered only on an “if and when available” basis, we cannot conclude that any of them ... can be categorized as a firm service. Unlike the truly firm service customer, the customers here have no assurance they will receive any service from FP & L under the transmission service agreements.

21 FERC at 61,245. Nevertheless, the Commission accepted the gist of FP & L’s argument that “[t]he services do in a sense become firm once they are undertaken. Whether for one hour, one week, or one year, FP & L is committed to using its system to provide transmission for that duration.” *Id.*The Commission therefore approved as “equitable” the allocation of capacity costs to all four kinds of transmission service. It did so without addressing Cities’ argument that short term service did not actually impose any capacity costs.

*787B. *Analysis*

In *Kentucky Utilities Co.,*15 FERC II 61,002 (1981), and the followup opinion denying rehearing, 15 FERC 1161,222 (1981), FERC set out at length its rationale for not allocating capacity costs to transmission service that was “interruptible.” In that case, the transmission service agreement gave Kentucky the limited right to interrupt or curtail service to the city of Paris up to 400 hours during any twelve consecutive months or 1000 hours during any five consecutive years. FERC held that even though service was not always cut off at peak demand, Kentucky could not include its capacity costs in the rate for this service: “because of the right to interrupt, Kentucky can keep Paris from imposing any demand on Kentucky’s system during peak periods and thereby control its capacity costs.” *Id.*at 61,004.

The Commission further explicated its reasoning in its opinion denying rehearing, 15 FERC 1161, 222, in which it distinguished earlier cases permitting the allocation of capacity costs to transmission service. For example, FERC pointed to several critical circumstances justifying the allocation of capacity costs to off-peak wheeling service in *New England Power Pool Participants, 52*F.P.C. 410 (1974), *rehearing denied,*54 F.P.C. 1375 (1975), *aff'd sub nom. Richmond Power & Light v. FERC,*574 F.2d 610 (D.C.Cir.1978). The Commission noted that the service in *Richmond Power*involved a reservation of capacity for the period service was provided. 15 FERC at 61,506. In addition, however, there was evidence that many of the transmission lines involved were heavily loaded at all times, with the result that the “coal-by-wire” transmission service did impose demands on the systems’ capacity. *Id.*Furthermore, the Commission had invoked special emergency powers to deal with the energy crisis; “the need to induce voluntary transfers of energy to forestall an emergency” under these circumstances was an important factor in the Commission’s decision and this court’s affirmance. *Id.*The Commission in *Kentucky Utilities*stressed these factors as justifying the assignment of capacity costs. We agree with FERC’s assessment in *Kentucky Utilities*of the basis for our own proposal of the allocation of capacity costs in *Richmond Power.*

The clear import of the Commission’s decision in *Kentucky Utilities*is that the allocation of capacity costs to transmission service must ordinarily be justified on the basis of the transmitting utility’s inability to avoid service at peak demand and its need to plan future capacity based in part on the transmission service at issue. This approach, which comports well with established principles of cost-based ratemaking, does not appear to have been followed in this case. FP & L’s own witnesses conceded that “one hour firm is not very firm.” J.A. 468. They acknowledged that requests for transmission service under an interchange agreement could and would be refused at peak demand periods when the system’s excess capacity was just sufficient to guarantee service to firm customers in case of an emergency. J.A. 473-77. They further admitted that FP & L did not take into account interchange transactions in planning its capacity. J.A. 457. The Commission nevertheless approved the inclusion of capacity costs because the service — even that for only one hour — was “in a sense firm.” It made no attempt to reconcile its decision with the *Kentucky Utilities*analysis.

The Commission now argues that *Kentucky Utilities*has no relevance to this case, which involves wheeling services and not ordinary transmission associated with the purchase of power. We are skeptical of this distinction. First, the Commission took note in *Kentucky Utilities*of the initial decision in the instant case. Although it declined to “opine” on the proper resolution of the capacity cost issue now before us, the Commission described that issue as “the very point discussed by Kentucky.” 15 FERC at 61,508. The Commission is therefore not well situated to deny the relevance of the *Kentucky Utilities*analysis to this case. Moreover, FERC has not explained the significance of the difference *788between ordinary transmission and wheeling for the decision whether to include capacity costs. In *Kentucky Utilities*itself, the Commission stated that it had approved a wheeling tariff which included capacity costs in *Cleveland Electric Illuminating Co.,*11 FERC ¶61,114, not because it involved wheeling but because the utility had undertaken an obligation to consider the future requirements of its wheeling customers in planning its transmission system. 15 FERC at 61,507. Although the Commission also referred to the fact that “the wheeling services are firm during the period the service is provided,” *id.,*the minimum period for which service could be reserved was one week, *Cleveland Electric,*11 FERC at 61,249, which is the maximum period that the Commission Staff in this case argued would permit the utility “to predict peak demand periods and refuse such requests selectively.” FERC appeared to attribute no great significance in *Kentucky Utilities*to the difference between wheeling and other transmission services.

We do not believe the Commission has adequately explained the reasoning behind its decision to allocate capacity costs to all classes of transmission service under the TSAs, including service for periods of only one hour. It is not enough to state that service is “in a sense firm.” If the utility is reasonably able to predict its peak demand periods within a week,29 we fail to see the cost justification for treating a “firm” commitment of service for periods as short as one hour differently from the interruptible service at issue in *Kentucky Utilities.*It is of course true, as the dissent points out, Diss.Op. at note 2, that a line must be drawn, and that any such line will be a fine one. But the Commission must nevertheless provide some rational explanation for the line it chooses.

A more comprehensive analysis may indicate that some fraction of capacity costs must fairly be allocated even to very short term wheeling service.30 The Commission may also bring to light practical concerns that justify the allocation of capacity costs to this service.31 However, in light of its recent full analysis in *Kentucky Utilities*as to why capacity costs should not ordinarily be assigned to transmission service which can be selectively refused at heavy demand periods and which does not require any additional capacity, we cannot uphold the Commission’s decision as it now stands, without an explanation of the circumstances that make it just and reasonable to assign capacity costs to all of the transmission services offered by FP & L.32

Conclusion

We are unfortunately unable to bring these lengthy proceedings to a close. FERC’s decision to reject Cities’ joint rate proposal was reasonable and supported by substantial evidence, and we affirm the Commission in that respect. However, the rationale behind the decision to allocate capacity costs is obscure and appears incon*789sistent with FERC’s own elaborate and reasoned analysis in *Kentucky Utilities.*We therefore remand to the Commission for further consideration of this issue and an explanation of the circumstances that either make its decision here consistent with the *Kentucky Utilities*analysis or justify a departure from that analysis.

*Judgment accordingly.*

1

. The four municipal customers are Fort Pierce Utilities Authority, Lake Worth Utilities Authority and the Cities of Homestead and Starke. They are supported in this action by intervenors Sebring Utilities Commission and the Cities of Clewiston, Green Cove Springs, Jacksonville Beach, Kissimmee and Vero Beach.

2

. This decision affirmed, with minor changes, initial ALJ decisions in Commission Docket No. ER77-175, 5 FERC fl 63,025 (1978), concerning transmission rates for New Smyrna Beach, and Commission Docket No. ER78-19, *et al.*(Phase II), 12 FERC f63,014 (1980), which consolidated proceedings concerning rates for numerous transmission customers. New Smyrna Beach is not a party to this appeal. *See infra*note 9. Docket No. ER78-19, *et al.,*was initiated in October, 1977, with FP & L’s proposal to limit the availability of firm wholesale service and to increase rates for the service. Proceedings were bifurcated into Phase I concerning restrictions on availability, and Phase II concerning rates. Only Phase II proceedings are at issue in this appeal.

3

. This may occur, for example, when one utility can generate additional power only by starting up a "peaking” unit with high fuel costs, while another has excess capacity on large generating units with low fuel costs. In this case, a computer will match the high-incremental-cost buyer with the low-incremental-cost seller, and the utilities can arrange a purchase at mutually agreeable *price*— i.e., a price that lies between the seller’s incremental cost and the buyer’s "decremental” cost.

4

. *See generally Gainesville Utilities Dep't v. Florida Power Corp.,*402 U.S. 515, 91 S.Ct. 1592, 29 L.Ed.2d 74 (1971) (discussing the benefits of increasing interconnection and coordination among utilities).

5

. Each utility is, at different times, both a buyer and a seller. Instead of the buyer paying transmission charges to the seller for such transactions, the utilities have a reciprocal arrangement by which each utility bears its own transmission costs when it is the seller. Therefore, as FP & L points out, all customers pay rates that reflect the cost of owning and operating transmission facilities. Brief for Intervenor FP & L at 5.

6

. Florida Cities initially challenged FP & L’s decision to file over twenty separate agreements rather than a single tariff setting out the terms under which any utility could obtain wheeling services. FERC ordered FP & L to file a single tariff incorporating, and thus making mandato*781ry, a company policy concerning the conditions under which wheeling would be undertaken. The Fifth Circuit reversed FERC, holding that such an order was tantamount to ordering FP & L to wheel power and was beyond FERC’s authority. *Florida Power & Light Co. v. FERC,*660 F.2d 668 (5th Cir.1981), *cert. denied sub nom. Fort Pierce Utilities Authority v. FERC,*459 U.S. 1156, 103 S.Ct. 800, 74 L.Ed.2d 1003 (1983).

7

. *Cf. supra*note 6. Cities are no longer asking FERC to order wheeling, either directly or indirectly, as the petitioners did in *Richmond Power,*574 F.2d at 620. They are merely protesting the rate applicable to any voluntary transactions that are undertaken.

9

. New Smyrna Beach, whose rates were the subject of Docket No. ER77-175, *see supra*note 2, is not a party to this appeal. However, the New Smyrna Beach example has been used by all parties to this appeal to illustrate their arguments as to the joint rate proposal, and the record before the Commission, as well as its decision, on the joint rate issue in Docket No. ER78-19 was based largely on the record and the analysis of the joint rate issue in the New Smyrna Beach case. *See*21 FERC at 61,243.

8

. In Part III of this opinion we discuss Florida Cities’ objection to the inclusion of capacity costs in FP & L’s cost-of-service calculations; that challenge is independent of its argument in favor of joint rates.

10

. FP & L witness Lloyd Williams described in more detail the application of this methodology to FP & L's transmission rates:

> To obtain the appropriate charge, it was necessary for us to determine the total annual cost of transmission service. This figure ($86,982,434) was derived by multiplying FPL’s investment in transmission facilities ($333,030,193) times our cost of capital and income taxes (16.71%). To the resultant figure of $55,649,345, we added 1976 transmission operating expenses other than income taxes of $31,333,089, to arrive at the total annual cost of transmission service of $86,-982,434. This amount was then divided by the average of the twelve monthly peak demands to obtain the transmission cost per KW of demand.

> This cost per KW was then converted to a charge by applying an adjustment for revenue taxes____ The necessary charge for transmission service on the basis of 1976 costs, is therefore, $13.46 per KW per year.

J.A. 28.

11

. The Commission strongly favors the "rolled-in” method of calculating transmission cc 'ts. *See*Otter Tail Power Co., 12 FERC ¶61,169 at 61,420 (1980).

12

. FPC’s "postage stamp” rate of $9.40/KW-year, together with FP & L’s rate of $13.46/KW-year, results in a cost to New Smyrna or any city requiring wheeling by both utilities of $22.86/KW-year.

13

. Of course, Cities also do not pay transmission charges for power they purchase directly from an adjoining utility. *See supra*note 5.

14

. This can be illustrated by the following simplified example. Suppose that FPC’s total annual costs are $150,000 and its peak load is 15,000 KW, resulting in a rate of $10/KW-year. Suppose further that FP & L’s total annual costs are $240,000 and its peak load is 20,000 KW, resulting in a rate of $12/KW-year. Instead of adding those rates ($22/KW-year), Cities would add the two utilities’ total annual costs ($390,-000/year) and divide by their combined peak load (35,000 KW), resulting in a single rate of $11.14/KW-year, which is the weighted average of the two individual rates. Cities’ actual proposed joint rate was $7.75/KW-year, less than either of the utilities' individual rates, because of other differences between Cities and FP & L on the costs that could properly be included.

15

. Cities’ joint rate of $7.75 would yield $2.88/KW-year to FPC and $4.87/KW-year to FP & L.

16

. This premise is clearly articulated in the initial ALJ decision in Docket No. ER78-19, 12 FERC at 65,053, expressly adopted by FERC in its own decision, 21 FERC at 61,243 (1982): "The shortfall in revenue [resulting from the joint rate proposal] will come from customers who transmit on only one system and are charged on the basis of costs on one of the two *784unmerged systems. Such a subsidy is rather obviously discriminatory."

17

. Cities argued that if two interconnected utilities (within a regional market) were required in order to complete a transaction, then, as a matter of logic, each performed only part of the full transaction, and the cost to each utility must therefore be only half the cost of a transaction that a single utility could complete. *See, e.g.,*Brief for Petitioners Florida Cities at 23; Initial Brief of Florida Cities at 69, FERC Docket No. ER78-19, *et al.*(Phase II) (R. 4872). But the Commission recognized that it is by no means a logically inescapable proposition that when FP & L wheels, taking on power at Point A and giving up power at Point B, the fact that FPC had to deliver power to Point A reduces the use of FP & L’s transmission network, and thus its costs, by about half. 21 FERC at 61,241.

18

. Cities' argument for why joint rates would not be discriminatory turns upside down usual notions of what constitutes price discrimination; they argued that transactions requiring wheeling by two utilities were different, and were therefore entitled to pay each utility only part of an average joint rate, because wheeling by two utilities was required in order to complete the transaction. The Commission of course responded that it was precisely that difference which, on the contrary, justified the supposedly discriminatory “double rates.” 21 FERC at 61,241.

19

. *See*Brief for Petitioners Florida Cities at 24-28. This argument appears not to have crystalized in the agency proceedings until well after the record was closed, in Cities’ Brief on Exceptions to the 1980 ALJ decision, J.A. 369-75. Cities’ primary arguments to the Commission are summarized *supra*notes 17, 18. Although we discern a significant shift in Cities’ position, its current position was presented to the Commission and we are not foreclosed from considering it.

20

. As noted, Cities' argument shifted during the proceedings. The Commission’s decision is responsive to Cities’ argument as framed throughout most of the proceedings, but did not evaluate the more fundamental claim of a unitary system.

21

. If the degree of coordination demonstrated by Cities between FP & L and FPC were sufficient to require the treatment of two transmission systems as a unitary network, the network would seem to expand indefinitely with increasing regional coordination. FERC therefore shared the concern of FP & L and FPC over the consequences if Cities’ version of joint transmission rates were applied to transactions over an *785increasing number of transmission networks. 21 FERC at 61,240. The virtually constant “average" rate called for by Cities’ analysis would yield to each utility a diminishing return from joint rate customers with no corresponding decrease in costs. Of course, if the systems did operate as a truly unitary network, this objection would lose its force.

22

. For example, a "Contract for Interchange Service between [FP & L] and Tampa Electric Company” contains schedules for interchange transactions during emergencies and equipment maintenance, and for economy exchanges. J.A. 248-274.

23

. In the case of economy exchanges, which may occur when one utility has excess capacity that it can make available at a low incremental cost to a buyer who could only generate the electricity it needs at a higher incremental cost, the exchanges are made on an hour-by-hour basis. At least in the case of the FP & L/Tampa agreement, *supra*note 22, the transactions are documented by the buyer within 24 hours after the exchange. J.A. 273.

24

. For example, the FP & L/Tampa agreement, *supra*note 22, provides for precise metering and billing of electricity transmitted across interconnections, and in-kind return of energy transmitted inadvertently as a result of human or equipment error. J.A. 237-38. These are only some of the provisions one would not expect to find among functionally merged transmission systems.

25

. Of course, we express no view as to whether it would be within FERC’s authority to order joint rates under the circumstances presented here.

26

. According to testimony by FP & L witnesses, most of the costs associated with transmission service are "capacity” costs; the incremental cost of transmitting electricity on an existing system with sufficient excess capacity is very small. J.A. 519-20.

27

. *See, e.g.,*Garfield & Lovejoy, Public Utility Economics 163-64 (1964) ("All utility customers should contribute to capacity costs,” but “a unit of firm demand for service should be allocated a greater share of capacity costs than a unit of demand that cannot pre-empt capacity on an equal basis with firm service.”).

28

. FP & L points out that the wheeling rates— f 1.65/megawatt-hour — are significantly lower than the transmission rates it charges its own firm wholesale customers — about $2.50/mega-watt hour. As we understand it, this is because FP & L, lacking an adequate basis for projecting demand under the agreements, did not “annualize" its costs; that is, it included in its wheeling rates only the capacity allocable to the electricity actually transmitted, whereas it bases its regular transmission rates on a pro rata share of the total capacity, including unused capacity, that it has to maintain throughout the year in order to provide reliable service at peak demand. *See*Brief for Intervenor FP & L at 25; J.A. 535-37.

29

. This was the contention of the Commission Staff in Docket No. ER78-19. 12 FERC at 65,-056, and we use this estimate for the purpose of illustration. Its precision is not critical for this discussion; even if the actual period within which peak demand could be predicted was only one day, commitments to wheel for one hour periods would appear to place no unavoidable burden on capacity.

30

. *See, e.g.,*Garfield & Lovejoy, *supra*note 27, at 163 ("All utility customers should contribute to capacity costs.”). Although FP & L's failure to “annualize” its transmission costs, *see supra*note 28, appears to reduce the capacity costs charged to customers under the interchange agreements, the Commission did not rely on or even discuss this point. We are not in a position to determine on our own whether the larger part of capacity costs still charged fairly reflect the actual cost of performing the wheeling service, short term as well as long term.

31

. For example, although it seems unlikely, it may be unduly burdensome to require separate rates for short-term and long-term services.

32

. The dissent finds FERC’s decision to allocate capacity costs not "plainly unreasonable,” and would affirm. Without any attempt by the Commission to reconcile its result here with the well-reasoned and, as we read it, contrary analysis of *Kentucky Utilities,*we do not sec how we can make that judgment.

MacKINNON, Senior Circuit Judge,

concurring in part and dissenting in part:

I concur in the majority’s determination that the Federal Energy Regulatory Commission (the “Commission”) is not required to order joint wheeling rates among interconnected utilities. I disagree, however, with the majority’s decision that the Commission failed to provide sufficient explanation for its decision to allocate some demand costs to wheeling services.

It must be noted first that in passing upon the reasonableness of rates, the Commission is entitled to a great deal of discretion. The Supreme Court, in the analogous natural gas situation, has admonished us that

> Congress has entrusted the regulation of the natural gas industry to the informed judgment of the Commission, and not to the preferences of reviewing courts. A presumption of validity therefore attaches to each exercise of the Commission’s expertise, and those who would overturn the Commission’s judgment undertake “the heavy burden of making a convincing showing that it is invalid because it is unjust and unreasonable in its consequences.” ... We are not obliged to examine each detail of the Commission’s decision; 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.”

> [The Commission] must be free, within the limitations imposed by pertinent constitutional and statutory commands, to devise methods of regulation capable of equitably reconciling diverse and conflicting interests.

*Permian Basin Area Rate Cases,*390 U.S. 747, 767, 88 S.Ct. 1344, 1360, 20 L.Ed.2d 312 (1968) (quoting *FPC v. Hope Natural Gas Co.,*320 U.S. 591, 602, 64 S.Ct. 281, 287, 88 L.Ed. 333 (1944)).1 The Commission enjoys similar discretion when the issue is how costs should be *allocated*among various customer classes in determining rates. *Consolidated Gas Supply Corp. v. FPC,*520 F.2d 1176, 1184 (D.C.Cir.1975) (quoting *Permian*Basin). *See also Louisiana Public Service Commission v. FERC,*688 F.2d 357, 359-60 (5th Cir.1982), *cert. denied,*— U.S. -, 103 S.Ct. 1770, 76 L.Ed.2d 343 (1983); *Alabama Electric Cooperative v. FERC,*684 F.2d 20, 27 (D.C. Cir.1982).

The Commission in this case found as a matter of fact that essentially non-interruptible service for a particular contract period was not “firm.” But it also found that it was *not*typical interruptible service such as that involved in *Kentucky Utilities Co.,*15 FERC ¶ 61,002 (1981), *rehearing denied,*15 FERC ¶ 61,222 (1981). The Commission concluded that it was equitable to allocate demand costs to such quasi-firm service.

The Commission, both before and after *Kentucky Utilities,*has consistently approved allocation of demand costs to wheeling transactions. *See New England Power Pool Participants,*52 F.P.C. 410 (1974), *aff'd sub nom. Richmond Power & Light v. FERC,*574 F.2d 610 (D.C.Cir.1978); *Indiana & Michigan Electric Co.,*10 FERC 11 61,295 (1980); *Cleveland Electric Illuminating Co.,*11 FERC ¶61,114 (1980); *Public Service Co. of New Hampshire,*24 FERC ¶61,007 (1983). This court approved *790of the practice in *Richmond Power & Light v. FERC,*574 F.2d 610, 621-22 (D.C. Cir.1978), noting that the Commission properly could conclude that wheeling services “should not be given a ‘free ride.’ ” *Id.*at 622.2 The Cities point to no case in which wheeling transactions or fixed-term contract service have been treated by the Commission as ordinary interruptible service.

*Kentucky Utilities*involved service interruptible at will. This case involves service that is essentially noninterruptible for the length of the contract period — whether one hour or three years.3 In view of the Commission’s considerable discretion — to which the majority shows little deference on this issue — I cannot say that allocation of demand costs to the latter category is plainly unreasonable. I would affirm this portion of the Commission’s decision as well. In my opinion my colleagues exceed their authority in remanding the wheeling phase of the case.

1

. Although *Permian Basin*is a natural gas case, the same standard of discretion "appl[ies] to ... review of an electric rate proceeding under the Federal Power Act." *Ohio Power Co. v. FERC,*668 F.2d 880, 886 (6th Cir.1982).

2

. The court cited with approval, 574 F.2d at 621 n. 44, such cases as *FPC v. Texaco Inc.,*417 U.S. 380, 387, 94 S.Ct. 2315, 2321, 41 L.Ed.2d 141 (1974) ("[t]hat every rate of every natural gas company must be just and reasonable does not require that the cost of each company be ascertained and its rates fixed with respect to its own costs”); *Colorado Interstate Gas Co. v. FPC,*324 U.S. 581, 615, 65 S.Ct. 829, 845, 89 L.Ed. 1206 (1945) (Jackson, J., concurring) ("I do not think it can be accepted as a principle of public regulation that industrial gas may have a free ride because the pipe line and compressor have to operate anyway”); *Consolidated Gas Supply Corp. v. FPC,*520 F.2d 1176, 1185-86 (D.C.Cir. 1975) (actual costs are not the sole valid considerations in setting rates); and *State Corporation Commission v. FPC,*206 F.2d 690, 709-10 (8th Cir.1953) (same), *cert. denied,*346 U.S. 922, 74 S.Ct. 307, 98 L.Ed. 416 (1954).

3

. To the majority’s assertion that there is little practical difference between a one-hour contract and purely interruptible service, I would answer that *any*line between firm and nonfirm service is likely to be fine. The Staff, for example, advocated using one week as the minimum period that would justify allocation of demand costs. But there seems to me to be little difference between service for 7 days, which the Staff would treat as firm, and service for 6 days, 23 hours, which the Staff would treat as nonfirm. Would allocating capacity costs to 7-day service agreements therefore be unreasonable? Line-drawing of this type is best left to the Commission.