A commitment with the state of Maryland to build new gas-fired and renewable power generation in Maryland meets a concern expressed by the staff of the Maryland Public Service Commission during the commission’s review of the proposed takeover by Exelon Corp. (NYSE:EXC) of Constellation Energy Group (NYSE:CEG).
Under a merger settlement with the state of Maryland announced Dec. 15, Exelon committed to develop 285-300 MW of new generation in Maryland, including 165-180 MW of renewable generation and 120 MW of gas-fired generation. The new generation projects will be built within the state, are expected to create more than 2,800 local jobs, and will benefit Baltimore Gas and Electric customers and the public by helping Maryland transition toward renewable forms of electricity. The total investment in energy generation is at least $625m. BG&E is a Constellation Energy unit that provides electric service to much of Maryland, particularly around the Baltimore area.
In Dec. 22 testimony filed with the PSC as part of the merger review case, company-sponsored witness Michael Schnitzer explained the commitment with the state for 120 MW of combustion turbine (CT) capacity in the 5004/5005 electricity subregion. Schnitzer is a director of The NorthBridge Group, a consulting firm.
From a capacity market perspective, the CT unit will be subject to the Minimum Offer Price Requirement (MOPR) provisions of the PJM tariff, he said. This would be the case whether Exelon owns the facility or if a new entrant owned the facility. Exelon will offer the unit into the capacity market at the MOPR floor price. A new entrant would have the option of offering the unit at a higher price but, in any event, could not offer it at a lower price than the MOPR floor price.
Once the new combustion turbine unit clears in a single auction, it will be subject to existing unit offer caps in all subsequent RPM auctions. The offer cap for CTs of this type is currently about $60 per MW-day, well below capacity prices in Maryland. If the CT were to be owned by a new entrant rather than by Exelon, it could not have a greater pro-competitive impact on the capacity market and capacity prices, Schnitzer added. But it could have a lesser impact if the new entrant offered the capacity at a price higher than the MOPR floor price. “Thus, from a capacity perspective, the CT is new entrant equivalent, and the fact that it would be owned by Exelon should not be a concern,” he said.
In terms of energy market participation, the provisions of a recent settlement agreement with the PJM’s Independent Market Monitor (IMM), specifically a section requiring Exelon to offer the unit into PJM energy markets at a cost-based cap (incremental cost plus 10% plus $1 per MWH). “As the IMM has testified, this is a competitive energy price offer, and consistent with how the unit would be offered if owned by a new entrant,” Schnitzer said. “Thus, in terms of both energy and capacity markets, the CT will be offered in a competitive manner, at levels that are equivalent to or superior to the offers of a new entrant.”
As for the solar capacity commitment in the agreement with the state, solar energy will flow into the grid whenever available, Schnitzer said. Depending on the nature of the facility (grid-connected versus behind-the-meter), the energy may be scheduled in the day ahead market , but as a price taker. The energy produced by the facility, and the effect on energy prices, is the same whether Exelon or a new entrant owns it. The capacity effect of behind-the-meter solar will be realized through the reduction in demand which translates to a lower RPM demand forecast. For grid-connected solar, the facility will be eligible for capacity credit as determined under PJM rules and will participate as a price taker in capacity auctions. Capacity market effects are the same whether the facility is owned by Exelon or a new entrant, Schnitzer said.
Exelon has also agreed to facilitate the development of a 10-MW poultry litter facility, which it would neither own nor control. “While separate from the 150 MW commitment in 5004/5005 and not expected to be operational by 2015, this commitment could facilitate the addition of 10 MW of baseload capacity and energy to the 5004/5005 region,” Schnitzer explained.
While the renewable generation commitment addresses other state policy goals unrelated to market power, this renewable generation will participate as a price taker in both PJM capacity and energy markets. Thus, the impacts on capacity and energy markets do not depend on whether Exelon or another supplier owns these facilities, Schnitzer said. “Thus, the 125 MW of new renewable capacity, like the new generation in the 5004/5005 region, is new entrant equivalent.”
The addition of new supply to the market has competitive benefits and can only result in a decrease in prices, Schnitzer added. “Here, because none of the new generation will be withheld by Exelon from the capacity or energy markets, the fact that the generation will be owned by Exelon rather than some other supplier does not diminish the price-reducing effect of adding new generation.”
PSC staff raised a market power concern in this case related to the potential near-term retirement of coal units at Constellation’s Crane and/or Wagner plants, which could be addressed through the addition of 150 MW of capacity in the 5004/5005 region. The generation commitment in the settlement provides for the addition of 150 MW of new capacity in the 5004/5005 region by 2015, and is specifically structured to address staff’s concern, Schnitzer said.
Exelon and Constellation, as part of their original merger plan, said they would sell the H.A. Wagner, C.P. Crane and Brandon Shores plants of Constellation. These plants are mostly coal fired, but included are gas/oil fired units located at the same sites. Collectively, these units have 2,648 MW of capacity. In a recent deal with the U.S. Department of Justice, the two companies formally agreed to sell those three plants to ease market power concerns in the PJM region.
The settlement with the state covers at least a total of 150 MW of new capacity commitments in the 5004/5005 region in Maryland by 2015, made up of 30 MW of solar and 120 MW of combustion turbine capacity. In addition, the company committed to 135-150 MW of Tier 1 renewable capacity in Maryland, which may be, but do not necessarily have to be, located in the 5004/5005 region. The commitment by the companies in their original merger application was for fewer MWs, and did not include any commitment in the 5004/5005 region of Maryland, Schnitzer noted.
Settlement with PJM market monitor restricts merged company
In companion Dec. 22 testimony filed at the PSC, company-sponsored witness Joe Pace outlined the benefits of the settlement with the IMM. Pace is an independent economic consultant affiliated with Navigant Economics.
“The IMM Settlement Agreement is layered on top of the applicants’ original mitigation package,” Pace said. “It accomplishes several things. First, it completely and effectively addresses the first concern about the applicants’ mitigation proposal by limiting potential buyers of divested generation to relatively small existing market participants identified as eligible buyers. Second, the IMM Settlement Agreement imposes significant behavioral constraints on the applicants’ bidding and operating practices for a ten-year period after the consummation of the proposed merger. These restrictions cover bids in the energy market by all nuclear and peaking units controlled by the merged company, and require the Conowingo hydro plant to be scheduled by PJM. The IMM Settlement Agreement also places significant constraints on capacity bid prices, unit retirements and ancillary service offers. These restrictions provide additional protections over and above those already achieved through the applicants’ initial mitigation proposal.”
Over 7,000 MW of the merged company’s total of 7,471 MW of baseload resources in the 5004/5005 market is nuclear capacity, Pace noted. Nuclear capacity has no operational flexibility and cannot be withheld from the market. The IMM deal formalizes the requirement that the merged company bid nuclear output as must run at maximum output, Pace said.
The great majority of the merged company’s non-nuclear capacity consists of relatively high-cost peaking units, with 2,848 MW or 68% of the remaining 4,192 MW of capacity being economic only during super peak periods. Virtually all of this capacity, basically everything but the output of the Muddy Run pumped storage plant, is covered by bidding restrictions in the IMM deal that are designed to assure that those units are offered competitively, Pace said.
The merged company’s mid-merit capacity will be only 1,344 MW in the post-mitigation world. Mid-merit units are not covered by the bidding restrictions in the IMM deal. However, the 5004/5005 mid-merit supply curve is relatively flat, reflecting the fact that competitors control substantial amounts of cost-effective mid-merit resources, Pace argued. “Indeed, in the post-mitigation world, the merged company will control only 8 percent of the mid-merit capacity in the 5004/5005 submarket,” he added. “Given these facts, there is no possibility that the merged company will be able to exercise market power when baseload or peaker units set PJM market prices, and no realistic prospect of doing so when mid-merit generation sets prices.”