Dynegy opposes a deal that would protect some of American Electric Power’s coal-fired capacity, and says this deal is not only anti-competitive in general, but also would potentially harm Dynegy and the other co-owners of the covered coal units.
AEP’s Ohio Power/AEP Ohio unit on Dec. 14 filed with the Public Utilities Commission of Ohio a stipulated agreement under which it has settled issues with some parties to a case where it is proposing to buy power from certain coal-fired units under a power purchase agreement for its retail customers, with that former Ohio Power capacity now owned by AEP’s non-regulated AEP Generation Resources (AEPGR) unit.
Dean Ellis, Dynegy’s vice president of regulatory affairs, said in Dec. 28 testimony that this new deal isn’t much better than what AEP has been seeking approval of all along.
“As stated in my initial direct testimony, Dynegy opposes AEP Ohio’s proposal for the PPA as well as AEP Ohio’s proposal to net revenues received and costs incurred related to AEP Ohio’s Ohio Valley Electric Corp. (‘OVEC’) entitlement, for which AEP Ohio already has a direct contractual relationship through an existing agreement. The Stipulation does nothing to change Dynegy’s opposition to the proposal,” Ellis said. OVEC owns the coal-fired Kyger Creek and Clifty Creek power plants.
Dynegy opposes arrangements or constructs that are designed to distort the markets in a manner that assure benefits to one market participant and therefore inappropriately disadvantage other market participants, Ellis wrote. “With its incorporation of AEP Ohio’s PPA proposal and OVEC entitlement proposal, the stipulation is just such an arrangement.
If approved by the commission, the stipulation will have a direct impact for years on Dynegy’s ability to compete with AEPGR and AEP Ohio in the wholesale markets. Under the proposed PPA, AEPGR will have all its costs covered plus a guaranteed 10.38 percent rate of return. All other merchant generators, including Dynegy, must compete for sales and bear the risk of lost revenues if they do not competitively price their generation output. The stipulation provides AEPGR with an advantage over other merchant generators, placing other existing merchant generators, jobs and tax revenue at risk.
“Further, because the design of the PPA remains cost plus, AEPGR and AEP Ohio have no financial incentive to act in an economically rational manner for the purchased output from the PPA units or the OVEC entitlement. Including the PPA units and the OVEC entitlement in the PPA rider will effectively encourage the continued operation of less efficient, less cost effective plants and discourage the modernization of generation sited in Ohio.”
In addition to harming Dynegy and other merchant generators, the stipulation harms the public in three ways, Eillis said.
· First, AEP Ohio’s customers must pay a subsidy to AEPGR.
· Second, the subsidy creates a disincentive for AEP Ohio and AEPGR to operate the subsidized units efficiently and to competitively market the units output in the PJM Interconnection market.
· Third, the subsidy will act as a barrier to new market participants who must put their own capital at risk to build or purchase generation units with no guaranteed rate of return to compete against AEPGR’s subsidized units.
Ellis noted that the covered Conesville Unit 4, Stuart Units 1-4, and Zimmer Unit 1 are only partially owned by AEPGR – the other owners are Dynegy and Dayton Power & Light. OVEC is owned by numerous entities in addition to AEP Ohio, including DP&L, FirstEnergy and Duke Energy. The PPA generating units partially owned by AEPGR are commonly referred to as joint owned units and are covered by joint operating agreements.
At page 23 of the stipulation and with regard to the units co-owned with Dynegy and DP&L, AEP Ohio has stated that it will open a docket at the PUCO by March 30, 2017, that will identify and remove any barriers to retiring, refueling or repowering those units. Additionally, AEP Ohio has stated that if it cannot get the co-owners (Dynegy and DP&L) to commit to the retirement, refueling or repowering of those units, it will report by Jan. 1, 2024, the steps it has taken to consolidate ownership.
Dynegy says it gets no benefit, and incurs some harm, for covered units it co-owns
Ellis said the ownership of these units is fractional in nature, where each party (AEP, Dynegy and DP&L) owns a share of the unit. Each owner offers (bids) its fractional share into the PJM energy and capacity markets, and each owner receives its share of the market revenues. On the cost side, the operations costs are split amongst each owner in proportion to their fractional share.
Ellis explained: “Should one owner receive an out-of-market subsidy such as the PPA rider, it will greatly distort the ownership arrangement. For example, if AEPGR were to receive an out-of-market PPA at above-market rates, the perverse effect would be that the PPA owner would be at a significant cost advantage, with the non-PPA owner at a disadvantage. Said differently, if one were to co-own a business with a business partner, and that partner were to receive a guaranteed, above-market subsidy, the subsidized partner would become agnostic to the prices at which the business sells its product eliminating any incentive for the subsidized partner to improve efficiency in operations.
“The result would be an increase in the cost of operations for the joint owners ultimately putting the non-subsidized partner’s ability to compete in jeopardy. In the case of AEPGR, it will not only receive its costs under the PPA but also a set return on equity of 10.38 percent – both disincentives to the efficient operation and capital investment in the PPA units. AEPGR will also have less incentive to consider any consolidation of ownership of the joint-owned PPA units with the long-term PPA in place. Approval of the Stipulated PPA proposal will also discourage efforts to maximize efficiency, reliability and profitability of the units due to diverging motivations and objectives of the joint owners.
“Typically, a merchant generator has a direct financial incentive to bid its capacity and energy into the market at prices that will be attractive to buyers yet attempt to cover operating costs and maximize margins to ensure the continued life of the asset. That requires merchant generators to carefully control costs, and carefully watch market pricing of a power market that fluctuates greatly depending on weather and economic activity.
“By contrast a regulated generator operating on a cost of service basis is not concerned about arriving at a price that will both attract buyers and recover its costs. It strives to keep its costs at the rates established and approved by the regulator (who generally sets rates based on units shown to be used and useful). The PPA and PPA rider construct is a hybrid of the competitive and regulated merchant generator constructs that awards AEPGR for years with the best elements of being an unregulated merchant generator without the down side of being a regulated cost of service generator.
“Under the Stipulation, AEPGR will be guaranteed a competitive market rate of return for years but without the risk of not making that return because of weak sales, increasing costs, or low priced competition. On the other hand, AEPGR will not have the risk typically associated with cost of service regulation that requires the units to be used and useful and to operate under set rates. And under the PPA, if costs go up, AEPGR can simply pass through those increased costs to its affiliate (AEP Ohio) which in turn will pass on the cost increases to its customers through the non-bypassable PPA rider.
“Simply put, the combination of the PPA and the PPA rider eliminates much of the cost focus and discipline required of a merchant generator to ensure cost recovery plus an appropriate return over the continued life of the asset. For example, if low gas prices and warm weather this winter depress prices in the Duke Ohio Zone, Dynegy will have to reduce or possibly eliminate its margin, carefully control costs and carefully watch the market in order to make a profitable sale into the market for the 46.5 percent portion of the Zimmer plant it owns. By contrast, with the stipulated PPA proposal in place, AEPGR will simply bill AEP Ohio its costs for its 25.4 percent portion of Zimmer plant and collect its 10.38 percent rate of return.”
Also, said Ellis, under the stipulated PPA and PPA rider construct, if AEPGR makes a reasonable effort to deliver but was unable to any resulting PJM performance penalties may be passed on to AEP Ohio’s customers. Using Conesville units 5 and 6 as an example, if the approximately 810 MWs bid into the auctions as capacity performance products fail to deliver when called upon, the penalties assessed by PJM could be as high as $128 million annually. The magnitude of this penalty and the potential ability of AEP Ohio to pass this cost through to customers would put the joint owners at extreme odds when it comes to decisions around reliability investments, he added.
It is anti-competitive to have ratepayers finance the addition of natural gas firing to the Conesville Units 5 and 6 while competitors like Dynegy would have to finance any such investments through their own working capital, Ellis wrote. Further, it appears that the co-firing as structured by AEP Ohio may just be “window dressing,” he said. The limits AEP Ohio has placed in the stipulation as to the coal heat input during gas co-firing are close to the units’ current coal heat input which would negate the use of natural gas.
Generally speaking, plants originally designed and built to operate on coal are most efficient and cost effective while burning coal, Ellis noted. There are many operational challenges in operating a coal plant strictly on gas, including boiler temperatures. In general, because of the poor efficiency related to the increased heat rate needed while firing natural gas in a co-fired unit, operating this type of plant solely on gas is usually the least likely operating mode if it is operated on gas at all.
Ellis was asked if Dynegy plans to use gas at Conesville 4, a coal unit not covered by the part of the stipulation having to do with co-firing. “No,” he replied. “As I indicated above, plants originally designed and built to operate on coal are most efficient and cost effective while burning coal. Dynegy did not purchase its interest in the Conesville unit 4 to operate that unit in a manner that would disadvantage the unit in competing in the wholesale markets. If AEPGR and AEP Ohio truly intend to operate the Conesville units 5 and 6 on natural gas, they will put those units at a disadvantage in the wholesale markets. It does not appear that AEPGR and AEP Ohio intend to operate the units on natural gas based on its historical heat input for those units compared to the heat input limitation of 28,737,180 MMBTUs that is at page 19 of the Stipulation.”
Ellis said the decline in heat input in recent years at Conesville Units 5 and 6 is generally consistent with the overall decline of coal-fired generation output nationwide including the PJM market, as natural gas-fired generation has become economic and cost competitive, along with overall flat-to-declining electric demand largely attributable to economic conditions and energy efficiency programs.
“Given that natural gas prices are projected to remain at all-time lows for the foreseeable future, it is reasonable to expect that the heat input will either remain at AEP Ohio’s proposed limit or even fall below that level without the addition of co-firing with natural gas,” he said. “In other words, AEP Ohio and AEPGR have given up nothing in exchange for the commitment to limit the coal heat input to the Conesville units 5 and 6. It will very likely continue to operate in the same manner as today and with the same emissions.”
Ellis said that if AEP Ohio were truly interested in providing a financial hedge to consumers, there are other effective and less costly ways to do so, including issuing a request for proposal (RFP) for the capacity and energy over the period in question. The RFP could take on a variety of forms, including a fixed-price option, a variable-priced option, or a combination of both.
The stipulated agreement, expected to be ruled on by the PUCO early in 2016, would require AEP Ohio to enter into an eight-year PPA (ending May 31, 2024) for the capacity, energy and ancillary service output of AEP’s 2,671 MW ownership share of nine units and AEP Ohio’s 423 MW contractual share of OVEC’s generation. The nine units include Cardinal Unit 1; Conesville Units 4, 5 and 6; Stuart Units 1-4; and Zimmer Unit 1.
The agreement includes significant environmental improvements to AEP-owned generating units including converting Conesville Units 5 and 6 to co-fire natural gas by Dec. 31, 2017, subject to regulatory approval, and retiring, refueling or repowering Conesville Units 5 and 6 and Cardinal Unit 1 to only use natural gas by the end of 2029 and 2030, respectively.