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Testimony: Constellation-Exelon Market Power Could Lead to Retail Supplier Defaults
September 24, 2011
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The Maryland PSC should, "ensure that as much retail load as possible it covered by fixed-price forward contract obligations signed far in advance of delivery (at least two years)," to mitigate market power impacts from the Constellation-Exelon merger, the Maryland Energy Administration said in testimony filed with the PSC Friday (9271).
Additionally, retail suppliers, "may be forced into bankruptcy," by any exercise of market power by the applicants, MEA added.
MEA presented testimony from Dr. Frank Wolak, who concluded that under certain conditions (such as the applicants running their units strategically to maximize profits), even if the applicants' recommended divestiture occurs and the assets are sold to a new entrant or a firm in the price-taking fringe, "market prices can rise substantially after the merger if the level of fixed-price forward contracts held by merging parties falls by a sufficiently large amount."
Specifically, under this scenario, Wolak said that the annual average wholesale price would be $54.60, which is 12.5% above the annual average baseline price of $48.50.
Wolak's analysis was based on the incentive of the applicants to exercise unilateral market power in an environment where they do not have fixed-price forward contracts for their generation (and thus would benefit from actions to increase spot prices.)
While Wolak cited a number of mitigation measures to address this (discussed below), Wolak noted that this potential exercise of market power would pose the greatest risk to retail suppliers.
In particular, Wolak noted that there is a strong incentive for retail suppliers to rely on the short-term market for their wholesale energy purchases to serve fixed-price retail load obligations. "This is a profitable strategy, particularly for a small retailer, under most system demand conditions," Wolak said.
However, Wolak warned of the wholesale price impacts to retail suppliers that would result if the applicants pursued a profit-maximizing unit operations strategy under a high-load scenario (e.g. demand greater than 2010 baseline), even assuming the proposed divestiture occurs and the applicants do not decrease their current levels of forward contracting.
Specifically, under this scenario, Wolak forecast a 37% wholesale price increase, to $66.50, resulting from the applicants' behavior.
"[W]hen system demand becomes unexpectedly high and wholesale prices rise (as they do in the high-load scenario described [above]), these retailers may be forced into bankruptcy or at least they must raise the retail prices they charge," Wolak said.
"Because of the increased risk that unexpectedly high load can lead to high prices after the merger described in the previous section, it important that the Commission ensure adequate fixed-price forward contract coverage of all retail demand post-merger," Wolak recommended.
"[T]he most important defense against any potential adverse consequences of the merger is to ensure that little, if any, retail load obligations within each state in the Relevant Market are not hedged by fixed-price forward contracts signed far in advance of delivery or served by retail tariffs that vary with real-time system conditions for customers with interval meters that record a customer's consumption on at least an hourly basis," Wolak added.
"The current Standard Offer Service (SOS) wholesale electricity auctions are a necessary condition for this to occur, but it is important to recognize that not all of retail electricity demand in Maryland is hedged by contracts purchased through these auctions," Wolak noted.
"[A] concerted effort can be made to ensure that as much retail load as possible it [sic] covered by fixed-price forward contract obligations signed far in advance of delivery (at least two years) or is sold according to a retail price that varies with real-time system conditions to customers with hourly meters," Wolak said.
Even though a two-year laddering process is used for residential and Type I SOS, the contracts are not signed two years in advance of the delivery start date.
Wolak also said that a key mitigation principle, cited by other parties as well as noted below, is to ensure that any assets divested by the merging parties are sold to a new entrant or small market participant rather than to one of the larger firms in the relevant market.
Wolak suggested that one means of implementing this requirement would be to require an associated fixed-price forward contract obligation as an asset sale pre-condition.
"For example, if a 200 MW unit is sold, then the buyer of that unit would be obligated to offer -- at a price set by the state regulator -- a forward contract for a specified number of years for some fraction of the unit's nameplate capacity in energy every hour of the day," Wolak said.
"The counter-party for this contract could be the default load obligation of the state and in this manner the forward contract purchases could be used to ensure against potential future increases in short-term prices that might result from the merger," Wolak added.
Additionally, to protect against the greater likelihood of harm from market power under high load growth scenarios, "the merging parties could offer a one-sided cap contract on the short-term price that is only in force if the level of demand in the Relevant Market High exceeds some pre-specified level during the next 3 to 5 years," Wolak suggested.
"This contract could have the following payment stream per MWh sold to the counterparty (again the default provider obligation of the state of Maryland), max(0,P(spot) – P(strike)). This means that the contract would pay the maximum of zero and the difference between the short-term or spot price, P(spot) and the strike price of the cap contract, P(strike). The merged party would have to pay P(spot) – P(strike) only if two pre-conditions occurred. First, the level of demand exceeded some unexpectedly high level during the term of the cap contract. Second, the spot price would have to be sufficiently high to exceed the strike price. Therefore, this cap contract would provide a strong financial disincentive for the merged entity to raise prices above P(strike) during the term of the cap contract," Wolak said.
Staff, OPC
PSC Staff, presenting testimony from David DeRamus and Songhoon Yang of Bates White, LLC, said that the proposed mitigation from the applicants is, "generally adequate to mitigate the merger-related increase in market power in the PJM energy market," subject to certain caveats.
First, Staff said that, without adequate mitigation, "the proposed merger would significantly increase market concentration -- and the ability to exercise market power -- in the relevant geographic submarket within PJM."
The 5004/5005 submarket, which includes Maryland, poses the greatest competitive concern, Staff said.
While the proposed mitigation my be adequate under certain conditions, Staff said that, "the adequacy of the Applicants' proposed mitigation depends significantly on the market position of potential buyers who purchase the divested plants." Screen failures would still exist under the merger if the plants were divested to one of the existing large players in the region, Staff said.
Due to such concerns, Staff recommended that the Commission direct the applicants to make a compliance filing after applicants have identified potential buyers to ensure that the post-merger and post-divestiture market concentration levels do not raise additional market power concerns in the relevant markets. If a compliance filing shows that the merger's potential harm to competition has not been sufficiently mitigated, applicants should propose additional mitigation to adequately protect Maryland ratepayers, prior to the Commission approving the proposed merger, Staff said.
"We do not recommend that the Commission impose explicit restrictions on the potential pool of eligible buyers at this stage of the proposed merger, because by doing so might harm the competitive purchasing processes and might foreclose consideration of certain buyers who may ultimately be beneficial for competition and Maryland ratepayers," Staff added.
Staff also noted that the physical divestiture proposed by the applicants consists of three mostly coal-fired electric generating facilities located in Maryland. "Since coal-fired facilities generally provide baseload or mid-merit generation, rather than the load-following or peaking generation that typically sets market prices in competitive markets, we would not generally consider coal-fired plants to be the best type of resource to be divested to address potential market power concerns. Nevertheless, we agree with the Applicants that the merger-related market power concerns raised by the standard economic models are most significant in off-peak periods, when these coal-fired facilities are economic, and on that basis, the proposed mitigation is reasonable," Staff said.
"We note however, that at least two of the facilities proposed for divestiture are older facilities whose useful economic life may be close to an end or that may require substantial additional investments to remain in operation over the foreseeable future. If additional evidence becomes available that these facilities are likely to be retired in the near term by a purchaser, we may revise our current conclusion that these particular plants represent adequate mitigation," Staff added.
"In general, the shorter the useful life of a divested asset, the smaller the amount of time its divestiture will counteract any market power concerns presented by the merger. For example, all coal units at the H.A. Wagner and C.P. Crane facilities are over 40 years old. A 2011 PJM study characterized coal units of this age to be at risk for retirement in the near term. If the H.A. Wagner (459 MW) and C.P. Crane (385 MW) coal units were to exit the market relatively soon after the divestiture, they would not serve as effective mitigation," Staff said.
"[T]he removal of these units from the market implies that the Applicants would have to add approximately 170 MW of additional divestiture (which must be economic in all time periods under study) in order to mitigate the post-merger competitive concerns," Staff testified.
"Once a buyer (or buyers) for the generating facilities proposed for divestiture is identified, the Commission should require that the Applicants and/or the Buyer present an analysis of the economic viability of the each of the plants going forward, with particular reference to the ability and willingness of the buyer to make appropriate investments in environmental compliance requirements to ensure that the plants at issue are likely to remain in the market for the foreseeable future. If the Applicants and/or the Buyer are/is unable to make such a showing, the Applicants should propose alternative plants for divestiture," Staff recommended.
The Office of People's Counsel, presenting testimony from Richard Hahn of La Capra Associates, said that the proposed divestiture is inadequate, and recommended divestiture of 3,080 MW versus the proposed 2,443 MW.
OPC discounted any mitigation resulting from the expiration of the Delta tolling agreement and the proposed sale of a 500 MW block of energy.
OPC's recommended additional divestitures are located in the EMAAC LDA, and include 16 units at the Croydon, Fairless Hills, Richmond, and Schuykill plants totaling 637 MW.
These units, currently owned by Exelon, are in most cases oil-fired, and no single unit is larger than 166 MW.
"These incremental units were selected because they were strategically located on the supply curve for the 5004/5005 market," OPC said. OPC's alternative mitigation plan, "allows the Applicants to retain all of either company's lowest cost generation at the lower end of the supply curve."
"Because none of the units proposed for divestiture by the Applicants were located in the EMAAC LDA, their divestiture would provide very little effective mitigation to address market power concerns in PJM capacity markets, especially in EMAAC where the greatest concern exists," OPC said.
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