PJM works on integrating Clean Power Plan into its power market planning

PJM Interconnection says the U.S. EPA’s proposed Clean Power Plan, which would cut CO2 emissions from existing power plants by 30% by 2030, is just another factor that the power markets will have to internalize, but with some unique issues that will need to be dealt with.

PJM on Feb. 5 filed with the Federal Energy Regulatory Commission a statement from Michael J. Kormos, its Executive Vice President-Operations, ahead of a Feb. 19 FERC technical conference on the Clean Power Plan.

“PJM is pleased to provide these initial comments in response to the Commission’s inquiry on the ‘Potential Implications for Commission-Jurisdictional Markets’ of the US EPA’s Clean Power Plan,” wrote Kormos. “Because in PJM our dispatch is based on cleared bids for capacity, energy and ancillary services, my work extends to ensuring the compatibility of our market rules with PJM’s operations and planning functions. I have overseen PJM’s response to the Mercury and Air Toxics Rule (MATS) as well as our work in modeling the impacts of the proposed Clean Power Plan rule.

“I appreciate the Commission’s focus on available tools to address issues which arise as both PJM markets and operations adapt to the impact of the Clean Power Plan. In a nutshell, the market is a tool which can be utilized to ensure efficient competitive outcomes in response to a particular set of state or federal policies. The markets do not drive policy outcomes but have proven resilient enough to respond to different policy initiatives. In that sense, they have proven successful in producing a diverse and competitively priced set of resources that are compliant with that policy. Whether it is the Sulfur Dioxide Trading Program of the 1990’s, the MATS rule or individual state [renewable portfolio standard] initiatives, the markets have been able to send the appropriate price signals that produce competitive outcomes.

“In some ways, the Clean Power Plan can be seen as another policy choice to which the markets will react. Just as with the MATS rule and state RPS rules, the EPA Clean Power Plan will adjust the type of resources that bid into the market but will not require wholescale market redesign. In this way, the markets provide an important role in revealing the least cost compliance options while also facilitating innovation by allowing new ideas to be tested and monetized if successful (or replaced if unsuccessful). The markets are also able to quickly internalize the costs of compliance and respond to any implicit or explicit price on carbon dioxide emissions. Whether a cap and trade system is developed on a regional basis or units simply have to bid their individual compliance costs, the market provides a sorting function that allows the least cost solutions to emerge.

“Finally, the market provides a source of transparency, independence and neutrality in revealing the true cost of compliance. By providing the sort function referenced above, the market reveals the least cost compliance plan that is consistent with the Clean Power Plan and all reliability requirements. For all these reasons, the markets that this Commission has helped craft since at least the inception of RTOs, represents a valuable tool that can absorb and respond to the changes brought about by the Clean Power Plan without any wholesale revisions needed.

Nevertheless, Kormos wrote, the Clean Power Plan does create some unique challenges given its very structure and the legal foundation of the rule itself:

  • For one, Clean Air Act section 111(d) requires the development of individual state plans, each of which must meet the compliance goal set by the EPA, and while the EPA encourages coordination between the states, it is not required.
  • Second, the rule requires individual states, as part of their compliance plans, to identify units and emissions reductions allocable to that state even if the state is part of a larger regional dispatch. The states also have flexibility to: opt-in new gas-fired resources subject to section 111(b) New Source Performance Standards, or; bring into their plans low utilization combustions turbines (defined in the rule as those operating at less than a 33% capacity factor) that are not otherwise required to be a part of a section 111(d) compliance plans. However, there is no requirement for consistency of these actions among the states participating in a single dispatch leading to an array of different treatments of new and low-utilization units based solely on the state in which they are located and that state’s particular treatment of these units.
  • Third, the state plan requires the balancing of a mix of resources some of which are within the markets and dispatch (such as renewable generation) and others which are not such as energy efficiency, building code improvements and “inside the fence” plant improvements.

“Clearly if there were an explicit price on carbon dioxide or another regional parameter that would be reflected in the dispatch, the market can produce efficient results inclusive of that constraint,” Kormos explained. “It is even possible for PJM to manage dispatch operations with multiple individual state prices on carbon dioxide as the explicit price can still be seamlessly incorporated into dispatch, although market outcomes may be less efficient than having a single regional price on carbon dioxide. Moreover, the interactions of one state’s price on another may make compliance more of a moving target. The more problematic issue arises if individual states adapt different compliance approaches which lead to different implicit carbon dioxide prices either at the state or by individual generating unit.

“That being said, individual states could effectuate their plans by placing state-directed run-time limitations on individual units just as they do today for Title V air permits or local ozone and NOx rules in non-attainment areas. These limitations to individual units within a state would be respected in the dispatch but potentially would lead to a less optimal result than if all plants were subject to a uniform constraint. Furthermore, there would need to be a reliability safety valve that would provide for the ability to violate these constraints if an RTO found itself in a situation where the unit was need for reliability but did not have any ‘run-time’ left. Absent an explicit price, it is unclear how an RTO would be able to allocate available run hours of units to when they are needed most.”

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.