Two power pools (em one existing, the other inchoate (em have announced that they will file tariffs to price electric transmission as the difference in spot prices in the generation and consuming markets. Revenues in excess of embedded costs would be distributed to the holders of firm transmission rights through "transmission congestion contracts" (TCCs).
"Locational pricing" and TCCs may achieve pristine economic efficiency in the generation and delivery of power. However, these concepts lie outside of "cost basis" in the traditional sense; they imply the virtual deregulation of transmission pricing.
While the Federal Energy Regulatory Commission (FERC) has encouraged "innovative"
transmission pricing proposals,1 particularly from pools, it nevertheless clings to the anchor of cost-based rates as historically adopted under the aegis of the Federal Power Act (FPA). In the past, when economic efficiency and the "just and reasonable" standard met, economic efficiency was generally lost. Will the FERC's recent embrace of competitive principles win the new day?
Locational pricing and TCCs lie central to the plans of new competitive power pools proposed by the California Public Utilities Commission (CPUC) and the Pennsylvania-New Jersey-Maryland Interconnection (PJM). These ideas will pose a challenge to the traditional utility ratemaking principles employed by the FERC under the "just and reasonable" standard of the FPA.
California: Comparing Prices
at Source and Load
The California commission did not address the allocation or pricing of transmission capacity in its May 1995 proposed decision2 on electric restructuring, because all electric generation and transmission assets would have been placed under the control of an independent system operator (ISO). Under that scenario, participants would purchase electricity only from a power pool; the price of power would reflect the bundled cost of generation and transmission.
But in its latest order, the Final Policy Decision3, the CPUC accepted a hybrid structure. Utilities will sell into and purchase from the Pool, but bilateral transactions will also be accommodated. The change is significant: the CPUC must now integrate power deliveries under the Pool and bilateral contracts; it also must allocate and price transmission services.
To accommodate this hybrid structure embracing a spot market for energy and direct bilateral sales contracts, the CPUC divided the formerly monolithic structure of the ISO into two distinct entities: The ISO and the Power Exchange. The ISO retains responsibility for grid operation and economic dispatch of generation resources. The Power Exchange will supervise the matching of power supply and demand bids. As the CPUC notes, bilateral contracts do not control the actual physics of the generation, transmission, and distribution that deliver the product the buyer consumes. Yet a dispatch nomination originating from a bilateral
contract places a burden upon the transmission grid, creating a liability for the cost incurred.
These costs, however, will not simply reflect the aggregate embedded cost of each transmission segment lying between the generator and a consumer. Instead, the ISO, in effect, will sell the generator's power to a different load located nearby, and instead serve the consumer with a purchase from a generator located nearer the consumer. In the absence of transmission constraints, the marginal cost of power at the two locations will be the same; the transaction will impose no economic cost on the system. If the system is constrained, however, the ISO may be forced to dispatch a higher-cost generator in the consumer's locale to accommodate deliveries under the contract, causing a locational pricing disparity. The difference in price at the two locales (em the higher-cost generator and consumer (em would constitute the transmission cost created by the bilateral contract, requiring compensation.
So long as the parties realize their interest under the bilateral contract and a settlement reimburses the ISO for any costs other than those associated with generation, the CPUC sees no need for the regulator "to take a proactive role in defining these settlement arrangements."4 Nevertheless, the CPUC acknowledges that many market participants will need some degree of certainty about future transmission costs to arrange long-term power transactions. Thus, the commission decrees that the ISO will administer a system of TCCs. The essential features of TCCs are not detailed; the CPUC simply directs the participating utilities to present the FERC with a detailed proposal that adheres to the minimum requirements specified in the Final Policy Decision.
Mechanically, coordination between the ISO, the Power Exchange, and bilateral contracts will work as follows. The Power Exchange will match generation and load bids for the next day, and submit a tentative dispatch schedule to the ISO. Parties to bilateral contracts will also submit their transactions to the ISO, with bids for increments and decrements of nominated inputs or outputs that would be available, if needed, to redispatch the system.
The ISO will determine locational marginal costs, incorporating the cost of generation, losses, and congestion. These locational costs in turn will define the market-clearing prices for the Power Exchange and the price of transmission used for bilateral transactions. The marginal cost of redispatch to provide an incremental load at each location will define the purchase and sales prices through the Power Exchange. The differences in the locational marginal costs between source and destination will define the price of transmission applied to a bilateral transaction.
Every winning generation bidder will receive the market-clearing price at its location. But customers will see only one clearing price, regardless of locale, because the Power Exchange will average the locational clearing prices for customers. Hence, the Power Exchange will collect more from customers (who pay an average price) than it will pay out to generators in the aggregate, based on specific locational prices. The net difference, plus transmission congestion costs paid in by bilateral traders, will be disbursed through the ISO to pay for transmission losses or as congestion payments under TCCs.
If the devil lies in the details, then the CPUC's discussion of transmission pricing and
allocation is a saintly piece of work. However, in supplemental comments5 filed in the FERC's Notice of Proposed Rulemaking (NOPR) on open-access transmission, the PJM companies provide a somewhat clearer view of the details of a pool operation based on transmission congestion contracts.
A Weighted-Average Surrogate
Currently, the PJM companies participate in a power pool that operates as a single control area with free-flowing ties among its members. The pool supports an energy market that uses a cost-based economic dispatch queue administered by the pool's control area operator (em PJM Interconnects Associates (em subject to the right of each individual company to self-schedule its owned (or contracted-for) generation to its own load. The PJM companies propose to modify their current pool structure (em including a shift to price-based dispatch and creation of an ISO (em to satisfy the objectives of the open-access NOPR.
The PJM companies say they will provide wholesale transmission services under poolwide transmission tariffs that offer comparable service to all market participants. Under these tariffs, load-serving entities (LSEs) within the PJM area will share the cost of the transmission system and thereby purchase equivalent network transmission service. Each LSE will use this network transmission service to bring energy from any source in the pool to its loads, on a firm basis.
The ISO will operate an hourly energy market with prices based on bids submitted by generators and their agents. Every generator will be required to quote a bid price in order to be economically dispatched by the pool. "Self-scheduled" resources will be required to declare a "floor" price. If the pool locational price falls below the floor, the owner must reduce the unit's output. The generator may declare a negative floor price, however, such that if the clearing price at a unit's location falls below zero, the owner would pay the pool to remain on line.
In the absence of transmission constraints, the hourly price for all energy bought and sold in the pool energy market will reflect the highest bid price for generators required to serve that level of load. When the system is constrained,6 the market-clearing price will reflect the incremental cost of serving load at different load and generation locations using the least-cost, security-constrained dispatch. The ISO will use this locational pricing method to collect congestion charges from the LSEs that incur them. These charges will be credited after the fact to the LSE and other purchasers of firm transmission service. Nonfirm transmission users will not receive credit from congestion charges.
Each LSE will be allocated firm capacity (de facto TCCs). If any firm capacity remains, the ISO will solicit annual requests for firm service on the bulk transmission system. If the ISO determines that sufficient capacity exists to provide the requested firm service, it will arrange the contracts between the appropriate parties.
PJM would employ an average interchange price (AIP) as a
surrogate for the unconstrained market-clearing price, defined as the weighted-average locational price of spot-market energy interchange sales and purchases. Prices at the source and load locations would be compared against the AIP. If the price at the source location exceeds the AIP, the differential creates a congestion charge credit to LSEs in the load location. Similarly, if the AIP exceeds the source-location price, LSEs at that location would receive the differential as a congestion credit. Revenues collected from parties involved in bilateral point-to-point trading would fund the congestion credits. (Those parties would pay the difference between the prices at the load and source locations.)
At this writing, companies supporting the PJM model were intending to file a comprehensive plan with the FERC by the end of May. The PJM states that its plan should meet the objectives of the Mega-NOPR without pro forma tariffs, which the PJM companies believe should not apply to power-pool services.
Breaking the Cost Link:
Just and Reasonable?
In effect, "locational pricing" will create a free-floating price for the interstate transmission of electricity (em a price wholly independent of the embedded "cost" of providing service. The immediate question, then, is whether locational prices will pass muster under section 205(a) of the FPA, which sets a "just and reasonable" standard for electric transmission rates.
Historically, regulators have closely linked the "just and reasonable" standard with depreciated embedded cost, irrespective of the price the market would attribute to the service provided. Thus, the FERC has traditionally allowed electric utilities to price firm transmission so as to yield annual revenues equal to the embedded cost of the utility's integrated transmission grid. For nonfirm service, the FERC has approved rates reflecting variable costs, plus a charge of up to 100 percent of fixed costs.
Can the law abide rates that ignore costs? Since the advent of utility rate regulation, economists have argued that cost-based rates breed inefficiency. If the sum of the costs do not equal the value society places on the resource, demand will exceed supply (em a phenomenon amply demonstrated by the distorted interstate natural gas market of the late 1970s. Conversely, a surplus will arise if the sum of the costs exceeds the resource value (em a result now amply demonstrated by "uneconomic assets" and excess generating capacity in the electric industry. Unfortunately, this economist's view has not yet prevailed in the courts.
The "just and reasonable" standard is not inherently incompatible with economically efficient rates or ratemaking methods. Indeed, in the celebrated Hope case,7 the Supreme Court held explicitly that the statute does not prescribe any single rate-setting method, but only an end result that qualifies as "just and reasonable." An end result that maximizes economic efficiency and reduces aggregate societal cost should suffice.
Nevertheless, the truth shows utility ratemaking to be infected with a virulent strain of populism. Economic efficiency has long taken a back seat. Instead, regulation has focused on protecting the public from "exploitation" by utilities (em defined as any utility earnings that exceed cost of service plus a reasonable return. Just as Nero watched Rome burn, the Federal Power Commission of the 1970s watched rolling curtailments in the interstate market while it sought to ensure that natural gas producers received no more than cost plus a reasonable return.
Controlling the Profits
In the coming debate on locational pricing, the D.C. Circuit's 1984 opinion in Farmers Union Central Exchange8 may offer guidance on whether transmission pricing can ignore costs.
That case remanded a FERC order that relied upon competitive forces to assure that oil pipeline rates would remain "just and reasonable." Granted, the court accepted the market price as a relevant consideration in ratemaking, but on balance the opinion buttresses those who argue that the "just and reasonable standard" mandates active regulatory supervision.
In Farmers Union the court held that a regulatory regime that could allow jurisdictional entities to earn "creamy returns" was incompatible with a congressional mandate to ensure "just and reasonable" utility rates. It found costs the most useful and reliable starting point to determine whether a rate is "less than compensatory" or "excessive." To the extent that noncost factors are considered, the court charged the FERC to articulate the nexus between the object to be served by the noncost consideration and its overarching responsibility to protect the public interest: "Ratemaking principles that permit 'profits too huge to be reconciled with the legislative command' cannot produce just and reasonable rates."9
Undaunted, the FERC has read Farmers Union as an indictment of its failure to demonstrate empirically the existence of adequate competition, as opposed to a directive that competition is merely a factor to consider in adjusting a cost-determined rate. The current FERC view holds that "light-handed" regulation may be warranted where a utility's market share is too low to permit it to withhold or restrict services to help boost the price by a significant amount for a significant period of time.10
Locational pricing for electric transmission goes well beyond the "light-handed" regulatory concept of Farmers Union; it would divorce rates entirely from historic costs. But if the FERC is correct in assuming the power to suspend the rules if competition is adequate, then "locational pricing" may well satisfy many of the FERC's transmission pricing goals. Yet the courts have never reviewed the FERC's interpretation of Farmers Union.
Back in its 1994 policy statement on electric transmission, the FERC cited section 212(a) of the FPA to support the idea that, to the extent practicable, transmission rates should reflect marginal costs rather than embedded costs.11 The FERC also observed that, as a matter of equity, incumbent customers should not pay for costs incurred in providing transmission services to new customers. Nevertheless, the FERC stopped short of abandoning cost-based rates, or even suggesting the possibility of "light-handed" regulation:
"Although the FERC has been willing, under appropriate circumstances, to permit market-based pricing for sales of generation, the FERC intends to treat market-based transmission rate proposals as nonconforming. Such rates obviously are not cost-based and the FERC does not believe market-based transmission pricing is appropriate at this time."12
At the same time, the commission left the door ajar for power pools and regional transmission groups to alleviate concerns that transmission might prove to be a natural monopoly.
In the past the FERC has relied heavily on embedded-cost rates, but it has also recognized the decidedly economic concept of opportunity costs in existing transmission tariffs. As the commission has noted, an electric utility incurs opportunity costs whenever it accommodates a third-party's request for transmission services to the economic detriment of its native-load customers.13 Thus, the FERC has accepted transmission tariffs that provide a rate that equals the higher of the utility's embedded or opportunity cost. Though not reflective of historic costs, locational pricing arguably calibrates and collects opportunity costs on a nearly real-time basis. However, the courts have concluded that a utility can charge only that rate that holds native-load customers harmless and does not produce excess revenue.14
The control of the ISO arguably should prevent any transmission owners from exercising market power. Moreover, compensating owners for the use of their transmission assets on an embedded-cost method (em with congestion rents paid to holders of TCCs (em should forestall any "creamy" returns.
The potential problem concerns the potential enormous value represented by transmission congestion contracts. In essence, the value of a TCC equals the difference between embedded cost and market value. Whereas the market value of transmission may constitute an opportunity cost, there is no correlation between the revenue generated under such contracts and the revenue requirement of the contract holders. This disjunction may prove particularly troublesome if TCCs are first allocated to the distribution function of existing utilities. Those utilities could then write their transmission capacity up to market, while recognizing the economic gain in the distribution function, but retained under the corporate umbrella.
This possibility was actually floated early on in the electric restructuring debate as a way to mitigate stranded costs: Utilities would simply write up transmission assets and mark down generation to match market valuation. However, such proposals were rejected out of hand as impermissible cost shifts. Arguably, TCCs would create precisely the same effect. Will pool allocations of TCCs confer economic value to the distribution function and, if so, should regulators apply that amount as an offset against stranded generating assets owned by the same utility?
Further, can nondiscriminatory transmission access exist where some hold firm capacity rights while others do not? Certainly the "have nots" may pay substantially higher net costs, leading to an anomalous situation in which nonfirm transmission service may cost exponentially more than firm service. How firm capacity is distributed in the first instance may either accentuate or mitigate discrimination under a transmission contract regime. Equal access becomes more problematic if TCCs are allocated to the distribution function at no cost. These difficulties could be minimized, however, if TCCs are allocated by auction, giving existing users a right of first refusal.
The Defining Moment
To the economist, cream-skimming returns issue a clarion call to new competitors, indicating a market that places a higher value on a service than on the cost of production. To the courts, "creamy" returns reveal just the sort of consumer exploitation that warrants a "just and reasonable" ratemaking standard. To economists, "uneconomic assets" arise naturally from that creative engine of destruction, the free market. To utilities and regulators, "stranded investments" mark "prudently incurred costs" that ratepayers should be required to pay.
The TCC concept may frame a defining moment in utility regulation (em that moment when the benefits of economic efficiency finally outweigh the historic aversion to potential profits that constitute the life blood of a competitive market. Coupling TCCs with the guaranteed recovery of stranded costs, however, creates strange bedfellows indeed. But perhaps the jargon that surrounds TCCs will sufficiently mask their true effect: economic efficiency bought with the political necessity of stranded-cost recovery. And perhaps the FERC may be persuaded simul-taneously to embrace market value for transmission rights
and cost recovery for stranded generation. t
Stephen Teichler is a partner at the law firm of Metzger, Hollis, Gordon & Alprin, Washington, DC, specializing in domestic and international energy law. He last appeared in PUBLIC UTILITIES FORTNIGHTLY as co-author (with Sheila Hollis) of "Collision or Coexistence: The FERC, the CPUC, and Electric Restructuring," Oct. 1, 1995, p. 19.
1 See, Inquiry Concerning the Commission's Pricing Policy for Trans. Servs. Provided by Pub. Utils. Under the Federal Power Act (Policy Statement), Dkt. No. RM93-19-000, III F.E.R.C. Reg. Preambles, (pp 31,005 (1994).
2 Re Proposed Policies Governing Restructuring California's Electric Services industry and Reforming Regulations, Decision 95-05-045, R.94-04-032, I.94-04-032, May 24, 1995, 161 PUR4th 217 (Cal.P.U.C.).
3 Re Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulations, Decision 95-12-063, Dec. 20, 1995, modified by Decision 96-01-009, Jan. 10, 1996, 166 PUR4th 1 (Cal.P.U.C.).
4 Final Policy Decision at 9, 166 PUR4th at 12.
5 Supplemental Comments of the Supporting PJM Companies for Technical Conference on Comparability For Power Pools, FERC Docket Nos. RM95-8-000, RM94-7-001.
6 The PJM explains that the uneven distribution of generating units with lower operating costs (predominately in western PJM or to the west of PJM) periodically causes an economic gradient of increasing marginal prices from West to East.
7 FPC v. Hope Natural Gas Co., 320 U.S. 591, 602 (1994).
8 Farmers Union Central Exch., Inc. v. FERC, 734 F.2d 1486 (D.C.Cir.1984).
9 Id., at 1502-1503, quoting Pub. Serv. Comm'n v. FERC, 587 F.2d 542, 559 (D.C.Cir.1978).
10 See, e.g., Statement of Policy and Requests for Comments, Alternatives to Trad. Cost-of-Service Ratemakings for Nat. Gas Pipelines, et al., Dkt. Nos. RM95-6-000, RM96-7-000, Jan. 31, 1996 (FERC).
11 Notice of Inquiry, note 1, supra, III F.E.R.C. Reg. Preambles, at 31,143.
12 Id., at 31,148.
13 See, e.g., Pennsylvania Elec. Co., 58 F.E.R.C. (CCH) (pp 61,278 (1992).
14 See, Pennsylvania Elec. Co., 11 F.3d 207 (D.C.Cir.1993).
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