Electricity Markets

Getting the price “right”: Deciphering the price formation debate

In the past few years, there has been a significant amount of debate and discussion about how to calculate prices in the wholesale electricity markets. Attention to “price formation” has been targeted to the energy and ancillary services markets operated by regional transmission organizations and independent system operators. 

The price formation debate was kick-started when the Federal Energy Regulatory Commission initiated a proceeding to evaluate price formation in the RTOs and ISOs in June 2014, which involved a series of full-day workshops, hundreds of sets of comments, and several rulemakings. Nearly five years after FERC launched this initiative, debates about price formation continue.

Advocates for price formation changes primarily argue that prices do not always reflect the true costs of providing energy and ancillary services, and therefore do not provide the correct signals for generation supply and demand response resource needs. Counter arguments, which the Association generally supports, are that major changes to pricing rules are not needed at this time, any rule changes that are implemented should have sufficient justification and demonstrate benefits to consumers, and energy and ancillary service prices should not duplicate capacity market payments.

While capacity markets are not the focus of the price formation debate, disputes about capacity market design are what prompted renewed attention to price formation rules. In capacity market discussions at FERC, generation owners argued that more attention should be given to the rules governing energy and ancillary services markets and prices, given that these markets can comprise a significant portion of a supplier’s revenue.

While supporters of price formation often argue that increasing the revenue from energy and ancillary service markets would decrease capacity market payments, such increases also create a greater risk of excess compensation between the energy and ancillary services markets and the capacity markets. For example, PJM Interconnection’s controversial March 29 proposal for changes to its rules for pricing operating reserves is estimated to increase both energy and reserve costs by about $2 billion per year, according to PJM’s initial estimate. Many PJM stakeholders, including public power, opposed these rule changes, stating that PJM has not justified a need for price increases of this magnitude. Moreover, these revenues will overlap with earnings from the capacity market, creating a double payment to sellers.

The issues up for debate

When it initiated its review of RTO/ISO price formation practices in 2014, the Commission stated that: “Ideally, the locational energy market prices in the energy and ancillary services markets would reflect the true marginal cost of production, taking into account all physical system constraints, and these prices would fully compensate all resources for the variable cost of providing service.”

The concept that energy and ancillary service prices must reflect the “true cost” has been a centerpiece of arguments in favor of price formation changes. In the RTO/ISO market rules, this concept of reclaiming true cost has been concentrated on four interrelated areas: uplift payments, offer caps, shortage pricing, and block-loaded resources.

  1. Minimization of “uplift.” Uplift payments are made to resources dispatched by the RTO to meet a reliability need, but whose cost exceeds the energy clearing price, known as the locational marginal price (LMP). Uplift is paid directly to that resource to cover these excess costs but is not included within the LMP. Because it does not impact the price, uplift is not a significant cost, currently equal to one percent or less of each RTO/ISO’s total market costs.

    Price formation reform advocates argue that all or most uplift should be included within the LMP to reflect the “true cost” of providing energy at that time. A counter argument is that some amount of uplift will always be necessary within the RTO/ISO operations to ensure reliability. Including uplift within the LMP would greatly increase the price without providing any additional benefit.

     
  2. Changes to energy offer caps. Until recently, offers to sell energy within an RTO/ISO market were capped at $1,000 per megawatt-hour. The rationale for this cap was to mitigate the exercise of market power. Following spikes in natural gas prices that occurred during the winter of 2013-2014, several RTO/ISOs began to allow sellers to offer above $1,000 during the winter if their costs exceeded that amount, but without allowing such offers to set the LMP.

    In November 2016, the Commission ordered the RTO/ISOs to increase the energy offer cap to $2,000 when the expected costs of producing energy exceed $1,000, and to allow such offers to set the LMP. The Association opposed the rule and requested that actual costs incurred above $1,000 be recovered through uplift. Allowing such higher offers to set the LMP could provide opportunities for the exercise of market power, while producing price spikes that are too volatile to provide meaningful price signals or incentives.

     
  3. Increases to shortage pricing. Market rules typically allow for the addition of a “penalty factor” to the energy price when there is a shortage of operating reserves or other indicators of shortage conditions. The theory behind shortage pricing is that sharp increases in energy prices during constrained periods can encourage both demand response and increased availability of supply from fast-start or flexible resources.

    In June 2016, the Commission issued a rule requiring the RTO/ISOs to remove any minimum duration from the definition of a shortage in their pricing rules. The Association questioned whether shortage events during brief intervals would simply indicate a transient shortage that could be resolved without necessarily triggering shortage pricing.

     
  4. Allowing block-loaded resources to set the price. Some resources produce energy in specified amounts or blocks, and some resources must generate at a minimum level (known as the economic minimum). For example, if an RTO/ISO required an additional 20 megawatts of energy in a given time interval, and the resource with the next highest price offer can only deliver a block of 50 MW, then that resource is dispatched, and a more flexible resource must be dispatched down by 30 MW to avoid excess generation.

    With some exceptions, these “block-loaded” resources cannot set the LMP. Without rules allowing block-loaded resources to set the price, the more flexible resource that was dispatched down sets the LMP, and the block-loaded resource is paid the difference between the price and its cost through uplift. Were the block-loaded resource to set the LMP, the resource that was dispatched down would face a price above their offer and an incentive to continue generating at the same level, resulting in excess generation.

All RTO/ISOs have rules that allow some degree of price setting by fast-start resources, even if block-loaded or dispatched at an economic minimum. Fast-start resources can be dispatched within a short time frame   and are an important component of the resource mix with higher levels of intermittent renewable resources.

In the end of 2016, FERC issued a proposed rule requiring the RTO/ISOs to allow fast-start resources with an economic minimum block to set the LMP, as well as to include commitment costs in the price offer, such as the costs of starting up and running a generator when not dispatched. In response to comments requesting more individual RTO flexibility, the Commission terminated the proceeding and opened individual investigations into three RTO/ISOs whose pricing rules were found to not sufficiently allow for such pricing -- PJM, the New York ISO, and the Southwest Power Pool. The Commission recently issued orders requiring the NYISO and PJM to implement certain rule changes to more fully allow fast-start resources to set prices, while the SPP case is still pending.

What’s current and what’s next

The Commission has concluded its price formation effort, aside from the still-pending SPP fast-start pricing investigation. In addition to the offer cap and shortage pricing orders, two more minor orders required the RTO/ISOs to align pricing intervals with dispatch intervals, and to submit certain information on uplift, operator actions, and transmission constraint penalty factors.

The RTOs are considering various price formation changes, although none appear to be as controversial as PJM’s proposal. The NYISO is evaluating changes to its shortage pricing, and MISO is considering enhancements to its fast-start pricing rules.

The California ISO and MISO have created flexible ramping products within the energy market, which compensate resources that are able to ramp up their generation quickly, and such a product is also under consideration by the NYISO. A flexible ramping product targets a specific resource type and differs from an effort to adjust prices with the hope of incenting needed resources.

As the RTOs/ISOs consider additional price formation efforts, stakeholders and the Commission should ask how well these market changes meet the following criteria:

  • What is the precise goal to be achieved, and will the rule change achieve that goal, or will its primary outcome be an increase in prices?
  • Is there a precise justification for the rule change, such as an inefficiency in the current pricing structure or a reliability need?
  • Will the change create an overlap between the energy and ancillary services markets revenue and the capacity markets and if so, how will that overlap be adjusted?
  • Will the change create additional market power concerns?
  • Finally, is there a net benefit to consumers?