Commission Watch
PJM/Midwest Market:
Should transmission owners get paid extra for distance and voltage?
While the Midwest now appears set on competitive bidding for the electricity commodity, taking from PJM such tried-and-true elements as locational marginal pricing (LMP), financial transmission rights (FTRs), and a day-ahead market with a security-constrained dispatch, the region remains split over the pricing of transmission.
The fight centers on the network of ultra-high-voltage transmission lines built years ago by American Electric Power (AEP). Who should pay for that network under a market regime? The dispute asks no less of federal regulators than how to divvy up the profits and spoils of electric restructuring across geographic regions and industry sectors.
J. Craig Baker, senior vice president at American Electric Power, says it's only fair to give credit to utilities and ratepayers for the value they have added to the transmission network: "Utilities that have invested in strong and highly interconnected transmission systems bring valuable assets that contribute significantly to the expansion of markets."
But on the other side, consultant Roy Shanker talks of a world ruled by commodity prices, as in PJM, New York, and New England, where the LMP at any given node defines the worth of the underlying grid assets: "Locational marginal prices coupled with financial transmission rights," he says, "these are the key economic signals. The basic energy markets are the best tool for reflecting the regional value of transmission."
But if the Federal Energy Regulatory Commission (FERC) can produce net savings by forging a huge power market from the Dakotas to the Atlantic, then Baker and AEP want a piece of that pie, to reward their shareholders (and ratepayers) for building a high-voltage network. They fear that if FERC dictates a classic PJM market design, with transmission not priced according to distance, voltage, or usage, that the power producers and consumers who export and import low-cost power-moving west to east-will corner all the gain.
The Two Rival Plans
Of two rival groups, one favors a license-plate regime, with consumers paying grid charges reflecting only the allocated cost of the lines owned by its native utility within its local control area. Consumers would cover that cost even if it included excess capacity. But they would not pay for any faraway high-voltage lines owned by other utilities, even if they used them to import power. This plan, known as the "Unified Plan," would echo the same basic pricing method already in use by the PJM grid operator. The grid access charge reflects the embedded cost of service of the lines located in the zone in which the load sinks. Unified Plan supporters include Alliant, Cinergy, most of the original transmission-owning members (TOs) of PJM, plus several stand-alone TOs, including ATC (in Wisconsin), ATSI (the FirstEnergy grid spinoff), International Transmission (DetEd spinoff), and Michigan Electric Transmission (formed from Consumers Power). ()
The other group proposes a variation of a method known as "highway-biway," but blended with a flow-based allocation. This idea, known as the "Regional Plan," would force a different sharing of savings earned from restructuring. Regional Plan supporters include AEP, Exelon, Allegheny Power, Ameren, Illinois Power, and LG&E. This minority group represents only 23 percent of the TO utilities in MISO and PJM,l but 40 percent of the value grid assets, and fully 55 percent of grid facilities rated at 345 kV or above. ()
By allocating grid costs based on voltage and usage, as per the Regional Plan, East-Coast consumers who import cheaper power from the Dakotas would pay some of the cost of the high-voltage and heavily used lines used to transport that power, wherever those lines might be located. Customers residing in Ohio or Kentucky, who take utility service from AEP, with its extensive array of high-cost, high-voltage lines, would receive compensation for the investment that their utility has made in the grid. They would now pay a lesser transmission charge, since they could throw off a portion of their grid costs to consumers in other areas who rely on those lines.
The Unified Plan represents the safe and familiar. The plan's proponents tout it as simple, convenient and workable-a "stable platform" on which to build a new power market in the Midwest, drawing on the experience gained from its use in PJM.
By contrast, the Regional Plan requires complex software to estimate the ever-changing flows of power across the grid, and to allocate costs accordingly. Yet proponents say the Regional Plan would apply long-accepted principles of rate making to achieve a fair and logical allocation of transmission costs.
Cost Allocations
Witnesses have estimated the total cost of service (TCOS) for transmission assets that would participate in the combined MISO/PJM market at $3.469 billion. The parties in the case have entertained a number of different possible methods of allocating those costs across the entire market, to design a rate for transmission access:
1. License-Plate Pricing. Treat all grid assets as serving local needs; allocate all costs by zone (control area) so that grid prices vary from zone to zone. Consumers who reside and receive power in any particular zone pay transmission rates designed to cover the costs of lines owned by the utility that serves that zone.
2. Postage-Stamp Pricing. Charge a single uniform access charge across the market, determined by dividing TCOS by total load served, yielding a rate of about $1.68/kW-month.
3. Highway-Biway Pricing. Divide all grid assets into two classes by voltage (high-voltage is "highway"; low-voltage is "biway"). Treat biway lines as local, and allocate as per method #1. Treat highway lines as serving regional needs, and spread costs over total market load, as per method #2. Take a weighted average of the two elements to the grid access charge in any zone.
4. Flow-Based (Usage) Pricing. Using a software program such as GE MAPS, estimate the power flows necessary to achieve a least-cost dispatch over the entire market area, and compare such flows to the "base-case" flows that would prevail if all consumers took generation supply only from plants and resources located in their local zone. The difference represents the degree of power flows attributable to regional needs throughout the market area (for exports and imports). Measure the cost of grid assets required to achieve those flows and serve those regional needs, and spread the cost across total regional load (in the same manner as highway assets are allocated as per method #3).
In its full level of detail, the Regional Plan would allocate costs under a blending of methods 1, 3, and 4. For transmission lines deemed to be dedicated to region-wide economic transactions, the plan allocates costs across zones with separate usage-based and voltage-based formulas, with a 50-percent weighting for each method. Smaller lines dedicated to local reliability would follow the traditional license-plate allocation. The plan proponents estimate that a market-wide cost allocation something like that shown in Table 1.
Critics and Cost Shifts
Note that the Regional Plan would create winners and losers among utilities (zones) across the MISO/PJM footprint. Table 2, derived from a presentation prepared jointly by the Wisconsin Public Service Commission and the Minnesota Department of Commerce, shows what portion of the grid assets in each transmission zone that would be treated as serving regional needs, and thus reallocated to consumers elsewhere. It also shows how much that consumers native to any particular zone would save (or pay extra) under the Regional Plan, as opposed to a strict postage-stamp method for allocating the cost of lines having a regional character.
As can be seen, native retail ratepayers of ComEd, AEP, and Illinois Power would see a significant amount of native grid costs reassigned to consumers in other areas. But so would the "classic" PJM utilities (the original trasmission owning utilities in PJM, as before the admission of Allegheny Power, AEP, ComEd, Dominion, Dayton Power & Light, etc.). These re-assigned costs would represent lines deemed to serve a market-wide purpose of facilitating power exports and imports.
By contrast, as the Wisconsin and Minnesota regulators point out, utilities and ratepayers in some zones would pay more in transmission rates than they would if the costs of these market-serving lines were allocated according to simple load shares.
Critics assail the Regional Plan also for its reliance on proprietary software (the GE MAPS program) to estimate the grid-flow dynamics required to achieve a least-cost, security-constrained dispatch. They question whether the software has access to reliable data on the costs and capabilities of power plants. And the Unified Plan sponsors observe that a rate design taken from the Regional Plan would force a continuing recalculation of line voltages and power flows, such as if a new TO should join one of the RTOs in the combined market area.
Nevertheless, the most troubling criticism observes that the Regional Plan engages in a recalculation of revenue requirement for transmission rates when, from a strict point of view, the FERC had asked the parties only to reconsider rate design.
Back in late September, FERC had opened a new proceeding to investigate and implement a new long-term pricing structure intended to eliminate seams in the combined region marked by the PJM and MISO RTOs. ()
In particular, FERC had required the elimination of pancaking "through-and-out" surcharges on transmission rates billed for crossing service territory boundaries, whether imposed by the RTOs (regional T&O rates, or "RTORs"), or by the individual utilities. As part of the deal to remove the T&O pancakes, FERC promised to make utilities whole over the short term by allowing a compensatory and temporary true-up charge (the SECA, or "Seams Elimination Cost Adjustment"). And to craft the SECA, FERC opened a broad settlement process, aimed at unifying the transmission price structure across the entire MISO/PJM area.
Thus, some Unified Plan proponents see the Regional Plan, with its flow-based pricing, as creating a stealth substitute to the old regime of T&O rates. Instead of pancaked charges that apply when power crosses boundary lines between control areas and utility service territories, they see a new regime of voltage- and usage-based charges that will increase transmission rates for many ratepayers-leaving them no better off than before, when they paid T&O rates.
Regulatory Roundup
Path 15 Upgrade. California ISO (Cal-ISO) runs into opposition with its unprecedented plan in Tariff Amendment 63 to make the Western Area Power Administration (WAPA) a "partial" participating transmission owner in the ISO, in trade for WAPA's 10 percent capacity interest (150 MW) in the Path 15 upgrade. Utilities complain that WAPA will receive a 10 percent share of FTRs and congestion revenues, though PG&E and TransElect will have paid for 99.5 percent of the line construction costs.
Gas Bypass Pipelines. Oregon appeals court reverses a state public utility commission (PUC) order, says a group of industrial gas users would violate state law providing for exclusive utility franchise rights if it forms a cooperative to bypass the local gas distribution utility and construct a pipeline to deliver gas to its members at retail.
Power Line Communications. Federal Communications Commission (FCC) OKs new rules for BPL (Broadband Over Power Line) systems to create a competitive regulatory framework for the use of existing electric utility lines to provide high-speed communications.
Gen Station Power Needs. Duke Energy said it could support Cal-ISO's claim that it was "stretched thin," and wanted first to gather and study data from power producers before investing money to change its billing and metering protocols and software on netting of on-site station power against unit output. Duke had complained to FERC to force Cal-ISO to conform to FERC precedent to permit its Moss Landing units to net their draws of station power against output from any other unit under common ownership, even if not operating instantaneously, and even if the two units are not directly interconnected.
ISO Retail Service. The Maine PUC said it would not require the New England Power Pool (NEPOOL) or ISO New England (ISO-NE) to obtain a utility license to serve an individual consumer (MPEU, or "Market Participant End User") with generation supply taken directly from the New England regional wholesale market. But a private power producer, trader or affiliate who facilitates the deal would require a license as a competitive retail energy provider.
Renewable Energy Portfolios. California appeals court overturns state PUC order that required electric utilities to pay costs upfront for upgrading regional power grid to accommodate sources of renewable energy to comply with a state law passed in 2002 that mandates a one-percent-per-year increase in renewable energy portfolios maintained by public utilities.
Gas Supply Risk. Regulators in Virginia were checking whether to allow Washington Gas Light to reclaim gas customers that had chosen competitive retail service from Metromedia Energy Inc. or to demand a larger security deposit from MME, to cover risk from higher futures prices and MME's increased share of the utility's design-day load.
Fuel Cost Hedging. Georgia PSC rules that Savannah Elec. & Power no longer needs any special financial incentive to operate its fuel cost hedging program, decides to flow fuel cost savings from hedging activities to ratepayers, ending prior practice of sharing 25% of such gains with company shareholders.
Utility Supply Solicitations. Ohio PUC OK's bidding process for FirstEnergy subsidiary Ohio Edison to solicit offers from power producers for energy supply, to assemble standard-offer portfolios for default retail customers. PUC appoints Charles River Associates to help analyze bids. No single bidder can win right to supply more than 65 percent of utility load.
Provider of Last Resort (POLR). The Pennsylvania PUC OK's three-year term with fixed prices for a POLR tariff for Duquesne Light, citing as irrelevant the utility's claim that it needed a six-year term to cut risk to help its unregulated affiliate buy the Sunbury plant.
Coal Seam Gas. Utah Public Service Commission (PSC) orders Questar Gas to refund some $25 million collected from customers to cover the cost of processing coal-seam gas produced near Price, Utah, saying that the gas was incompatible with appliances and posed a danger to retail customers.
Deceptive Marketing Practices. Illinois Commerce Commission rules that private natural gas retailer Peoples Energy Services Corp. violated state law by inviting customers to lock in a fixed price (62 cents per therm) for more than a year, while reserving the right at any time to send a "pricing notice" to customers with a new higher rate that would be binding absent the customer's written objection within days.
Renewable Portfolio Standards. New Jersey BPU ok's a financing arrangement with the PJM RTO to develop and implmement a Generator Attributes Tracking System (GATS) to identify qualifying resources and verify compliance with state programs to promote renewable energy.
Retail Electric Competition. Citing significant market power in wholesale power supply, plus a dearth of alternative retail electric vendors, utility regulators in Virginia in a report to the governor (Sept. 1, 2004) questioned whether retail electric competition can bring lower power prices to consumers than would have been the case under traditional regulation.
Promotional Utility Advertising. The Maine PUC dismissed a customer complaint that Central Maine Power's campaign of promoting the use of electric-consuming appliances violated the public interest by increasing environmental degradation and domestic dependence on foreign oil.
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