How rules muted price signals and did not ensure efficient siting.

Of the new rules proposed by the Federal Energy Regulatory Commission (FERC) for interconnecting new power plants to the transmission grid, the most controversial (for transmission providers and generators alike) is FERC's choice of who should pay to construct the various categories of required new facilities.

Some transmission providers argue that interconnecting generators should pay the full costs of all transmission upgrades that are required to interconnect a new generator to the power grid, and which would not be required for grid expansion (to meet load growth, for instance) absent the new generation project.

Generators claim, however, that their presence on the grid benefits all power customers-through increased competition, lower energy costs, etc.-so that all transmission customers should share in paying grid upgrade costs.

The FERC, meanwhile, takes a middle course, but one that seems more offensive to grid owners than gen project developers.

Under the FERC's proposed standard interconnection agreement (IA), the costs associated with the design, construction, and ownership of all of the interconnection facilities, including the network upgrades, would be assigned to the generator.¹ So long as the transmission provider receives payments for transmission service under such upgrades, the generator would be entitled to recover these costs through refunds from the transmission provider, with interest, within five years from the date of the network upgrades.²

In choosing such a policy, FERC has concluded that current rules and practices pose sufficient barriers to entry, and thus inhibit the development of competitive generation. Yet at the same time, while attempting to stimulate construction of new generation, FERC's new rule provides no new price signals to guide developers on where to build their new plants. Indeed, experience demonstrates that a cost allocation mechanism like that proposed in the interconnection NOPR, by itself, mutes siting signals that would otherwise be provided if the full costs of completing necessary transmission upgrades were born by the new generator.

Consider New England, and the lessons learned about the importance of including location-specific price signals for power plant developers.

Several years ago, New England adopted a new set of gen interconnection rules and procedures-well thought-out, like those that FERC now has proposed. Beginning in 1997, many crucial elements came together in New England and spawned an explosion in merchant plant development. At that time, New England had relatively high-priced electricity. The New England Power Pool (NEPOOL) had restructured to include open membership for all market participants. It had filed to implement bid-based markets for generation and regional open access transmission service. Access to fuel supplies was being expanded with the construction of the Maritimes and Northeast Pipeline (M&N Pipeline). The NEPOOL transmission system was perceived to be robust, with little to no congestion. Although NEPOOL's restructured electricity market was envisioned ultimately to provide an acceptable congestion management system, the market initially implemented for NEPOOL reflected region-wide clearing prices. Congestion management was intended to be implemented promptly following prove out of the markets.³

In these circumstances, generation developers flocked to New England, proposing an unprecedented number of new gas-fired merchant generation facilities. Soon after initiation of restructured markets, more than 30,000 MW of new generation was proposed, and in a queue for a system that had peak loads of only 25,000 MW. Some officials from ISO New England attributed the result to "irrational exuberance." And much of that exuberance was focused on Maine, where relatively inexpensive, undeveloped land was plentiful, fuel was readily accessible from the newly installed M&N Pipeline, and the backbone transmission system could be reached with relatively little transmission investment. To further fuel this development boom, FERC took note of a complaint by a proposed generator and ordered changes to how interconnection requests were handled and analyzed in New England. A long-standing interconnection procedure had required expansion of the transmission system in a way that did not foster congestion. This procedure was replaced with an interconnection procedure that looked only at the minimum amount of transmission upgrades necessary to ensure that a new generator did not adversely impact the reliability and stability of the grid.

NEPOOL responded with a new interconnection procedure administered by ISO New England that is identical in most respects to the interconnection procedure now proposed by FERC in its interconnection NOPR. But because LMP was not in effect in New England, generation developers lacked good, location-specific price information that reflected fully the economics of locating their projects in Maine versus other locations within NEPOOL. To resolve issues with how to allocate the interconnection costs for new generation, NEPOOL negotiated a settlement. It required all generators who were ranked high in the queue to pay all of their direct interconnection costs, plus one-half of the remaining transmission upgrade costs required to satisfy the new FERC-imposed minimum interconnection standard.

This combination of factors led developers to propose more new gen capacity for Maine than either was needed or could be exported in certain conditions. Maine's load, which peaks at about 1,800 MW, represents only about six percent of New England's electric load. At one point, however, the amount of new generation proposed for Maine and in the interconnection queue was over 6,000 MW, which was approximately 20 percent of the new generation proposed for all of New England. Over time, some of these plants were delayed or canceled. Five new plants totaling approximately 1,650 MW eventually were constructed, coming on-line between February 2000 and March 2001. (Table 1 shows the system conditions prior to the new power plant development. Table 2 shows the system conditions after construction of the new generation.)

These figures demonstrate what happens when siting signals do not fully reflect the actual economics of the system. An overabundance of generation was constructed within an area that had insufficient load and export capability to support the full dispatchability of the generation within the area. As a result, the NEPOOL markets are not able fully to realize the benefits of this new competitive generation. Since the plants were constructed, New England consumers have paid tens of millions of dollars more for power, and Maine generators have lost revenues, because the Maine plants could not operate at economic levels due to transmission congestion (, the Maine plants were constrained down). ISO New England has calculated these costs at approximately $55 million during just several hours of transmission congestion since June 2001.

We cannot turn back the clock on this situation. It is very likely, however, that different siting decisions would have been made if LMP were in effect, and developers had available to them historical and projected LMP information. Substantial investment in the New England bulk power system may have been redirected to other critically important sub-areas in the region such as southwest Connecticut and greater Boston, where congestion has increased consumer costs in the region.

If FERC should move ahead with its gen interconnection rule, but without integrating the rule with full LMP, as that term is understood in the commission's companion effort to standard market design (SMD) for wholesale power markets, then we likely will see the New England experience played out in other areas of the country. Generation developers will lack critical information necessary for them to make the most economic business decisions, and may be subject to new mitigation procedures that substantially alter the economics of their investment. These factors can prevent realization of the full benefits of competitive markets.

Everyone can learn from the New England experience. FERC should not implement the cost allocation provisions of the interconnection rule as proposed in its NOPR prior to the implementation of an SMD rule that adopts LMP as the standard for congestion management and market design. While implementation of the proposed interconnection procedure may be useful before the related cost allocation provisions are implemented, the proposed cost allocation provisions should await LMP. In establishing interconnection cost allocation rules for power plant projects during the critical transition period between current markets and proposed markets, FERC should consider mechanisms that would enhance proper long-term siting decisions while LMP rules and information are being developed. Power plant developers should anticipate in their modeling and power sales agreements not only the existing and proposed markets, but also the markets as they will evolve. Customers should carefully structure their power arrangements through the transition period to reflect how congestion is likely to be addressed before implementation of SMD. For state officials, any retail restructuring initiative and siting decisions should consider and address issues as they appear under current rules and might appear under proposed rules, and also as they may develop during this critical transition period. It is only through careful consideration not only of where we are now and where we want to go, but also how we will get there, that proper siting of new generation will foster full and broadly competitive markets for years to come.

1. See § 11. Section 10 states that the generator is also responsible for all of the operating and maintenance expenses for the generator's and the transmission provider's interconnection facilities.
2. § 11.4.
3. LMP is now anticipated to be implemented in NEPOOL later this year or early next year.

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