The latest dispute over PJM’s bidding rules has raised the level of uncertainty in organized electricity markets. Efforts at reform have created a market structure so jumbled that it can’t produce...
Transmission is Bubbling
A billion-dollar ‘gold rush’ could send grid rates through the roof.
to 24 percent of total CMP delivery-only rates” (Motion to Hold Petition in Abeyance, p. 18, FERC Dkt. EL08-77, filed Aug. 29, 2008) .
In defending incentives for its MPRB project, Central Maine projects that its interest coverage ratio during the construction period will decline from 4.4 to 3.4, a figure more characteristic of companies with credit ratings lower than CMP’s current BBB+/A3 ratings. It adds that a FERC incentive allowing current rate recovery of CWIP would help boost its coverage ratio to 4.2 during the height of construction.
Maine PUC analyst Richard Kivela counters, however, that for T&D utilities like CMP (and MPS) that have divested themselves of generation assets and which carry very low business risk profiles, the S&P guidelines indicate that a 4.2 coverage ratio actually would be consistent with a “high-A” to “low-AA” credit rating.
Kivela adds that CMP’s case for incentives is undercut by Iberdola’s friendly merger offer of $28.50 per share for stock in CMP’s parent company, Energy East. According to Kivela, Iberdola’s offer represents a premium of more than $1.2 billion over book value, indicating that an appropriate ROE for CMP would fall within the range of 10.5 to 11.0 percent—substantially lower than CMP’s requested figure 13.14 percent, reflecting FERC incentives for grid expansion.
Maine Makes a Market?
In August 2007, ISO-NE released the final draft of its “New England Electricity Scenario Analysis,” in which the RTO documented that the region would need another 8,000 MW of electric capacity by 2020 to 2025, but that adding gas-fired capacity to meet that challenge (the likely capacity of choice absent major changes in RTO policy), would expose the New England region “to potentially high prices and additional fuel-diversity issues.”
The analysis concluded that alternative paths favoring renewables could save New England over $1.5 billion per year (almost 14 percent of total system costs) versus the “business as usual,” carbon-heavy path represented by power plants already proposed and listed in the region’s interconnection queue.
In particular, the report favored wind and other similar generating choices that could provide energy “at low to no fuel cost,” thereby resulting in “the lowest system-wide electric energy prices, emissions, and use of fossil fuels.”
That policy document today drives much of New England’s big picture planning. Yet it appears that facts on the ground are conspiring against such thinking.
First, EPAct and FERC’s interpretive rules for grid-expansion incentives reward only those projects that ensure reliability or reduce line congestion, and MPC, unfortunately, does neither.
In fact, New England as of 2007 had “little persistent transmission congestion,” according to Stephen J. Rourke, ISO-NE vice president for system planning, in remarks he gave on July 9 in Hartford, at a DOE workshop on transmission congestion .
Second, MPC likely would not even cause spot-market energy rates to fall much in New England, since the RTO’s single-price auction market for energy relies on locational marginal pricing, and even a large dollop of imported wind capacity probably would not displace gas-fired turbines from their position as the price-setters operating on the margin.
Third, the MPC project