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FERC Staff Report Confirms Capacity Market Designs Not Ready for Prime Time, Texas Implementation A FERC Staff report issued ahead of a technical conference on capacity markets in the FERC-jurisdictional RTOs confirms that current capacity market designs are not desirable for implementation in Texas, and that if Texas were to adopt a mandated reserve margin, it will need to look at novel approaches to meeting such mandate, because existing capacity markets are poorly equipped to face new challenges, particularly those currently facing the Texas electric grid.
Specifically, the Staff report confirms that current capacity markets are not designed for a world with large-scale intermittent resource penetration -- as is the case with ERCOT.
Current capacity markets, designed nearly a decade ago, do not take into account "operational needs," and instead rely on an outdated notion of resource adequacy tied solely to installed capacity. However, as the ERCOT experience has proven, having adequate installed capacity, even in excess of the reserve margin, is no guarantee of "reliability", as ERCOT's two instances of rotating outages in the past decade came when installed capacity was well in excess of the reserve margin.
Notably, no RTO relying wholly on a capacity market for resource adequacy has the intermittent resource market penetration seen in ERCOT. This alone should cause Texas pause from rushing to implement an "off the shelf" capacity market design.
However, the FERC Staff report goes further, noting that it will not be a simple matter to merely graft operational parameters onto existing capacity product definitions.
Instead, the discussion from the Staff report supports a view that a "clean sheet" approach would be better, and that focus should be on market designs that promote operational flexibility (such as scarcity pricing, and any elements to support appropriate scarcity pricing such as an operating reserves demand curve), rather than trying to update a decade-old market design for a new world.
The FERC Staff report notes that, "An emerging issue is whether the basic definition of the capacity product should account for specific operational attributes needed to address system needs."
"While the centralized capacity markets include a locational component to account for transmission constraints and ensure that capacity is available and deliverable to load, other operational considerations are generally not considered when defining what types of capacity the market will procure," the Staff noted in reviewing currently implemented capacity market designs (emphasis added).
"As the electric industry and wholesale markets evolve, the capacity market may need to take additional operational needs into account," Staff said.
"The characteristics of potential capacity resources also must be considered. While the eastern RTO/ISO centralized capacity markets have incorporated certain non-traditional resources, some rules and requirements may still present barriers to new technologies that could otherwise meet the definition of the capacity product, and thus impair the ability of the markets to procure resources best suited to meeting future operational needs," Staff continued.
"For example, changes in the electric industry have created additional operational and system requirements, including an increased need for more responsive and flexible resources, e.g., quick start and fast ramp capability, responsiveness in providing regulation or load following, etc. In particular, the rapid growth in variable energy resource integration creates a greater need for flexible resources to balance load instantaneously and to smooth fluctuations in output during the operating day," Staff noted (emphasis added).
"Other emerging challenges include the increasing reliance on natural gas-fired generation in some regions where gas-fired resources rely upon a 'just in time' fuel delivery system, which can create an additional need for access to a diverse set of resources. Additionally, in some control areas older units that are relied upon for peaking, ramping, or reserves may not be performing within their offered parameters, potentially requiring a new product definition that accounts for resource performance. Environmental regulations may also limit the operation of some generation resources that could consequently result in resource adequacy concerns in local areas," Staff added.
However, current capacity market designs -- including those most sought by capacity market supporters in Texas -- fail to account for any of these challenges.
Current capacity markets do not require capacity suppliers to meet obligations for start-up time, minimum run time, minimum down time, or other operational parameters that would address specific system needs such as quick start and fast ramping capability, or load following ability.
Moreover, simply adding these metrics to the current capacity market designs is not a straightforward task.
"[R]edefining the capacity product to procure needed operational attributes, defining the specific attributes to be procured, and determining how much of the overall capacity requirement should be met by capacity resources with such attributes would be a complex undertaking. Co-optimizing the procurement of different capacity products to ensure an overall least-cost result for customers also would add significant complexity for system operators and market participants," FERC Staff noted.
FERC Staff also noted that current capacity markets do not take into account the growth and impact of distributed resources. Currently, "[d]istributed generation, storage resources, or demand response may not meet minimum size requirements (absent aggregation) or minimum discharge time requirements," under the capacity market designs, Staff noted.
Given that the chief executive of the parent of the largest retail electric provider in Texas (and also one of the largest capacity owners) sees distributed solar as disrupting the electric industry, Texas would need to confront any capacity market design that fails to recognize this reality. In particular, Texas would need to ensure that such distributed solar is properly accounted for in the market, and that customers are not double-paying for capacity by having such distributed solar excluded from meeting the capacity requirement.
FERC Staff also noted long-standing challenges inherent in the existing capacity market designs, including whether the forward procurement commitment period (one to three years forward), and pricing commitment period (one year only) are adequate to support new entry by capacity, and the risks placed on customers from the length of the commitments.
Staff noted that, "a longer forward [commitment] period can result in increased risk for customers when compared to a shorter forward period. Forecasts of planning reserve margins are generally more accurate closer to the period in which capacity resources are needed, when market conditions are better known."
"In addition, using a longer forward period that accommodates the construction of longer lead-time resources can be problematic for resources with shorter lead times, like demand response, which may face difficulties in securing customer commitments so far in advance," Staff noted.
As to the pricing commitment period, Staff noted that a longer commitment period may help promote market entry and increase competition. "Some suppliers claim that a one-year commitment period provides an insufficient incentive to take on the risk of building a new power plant," Staff noted. Such suppliers, "have expressed a strong interest in longer commitment periods, similar to long-term purchase power agreements, arguing that the lack of certainty regarding long-term fixed cost recovery can present an obstacle for new entry and obtaining non-recourse project financing," Staff noted.
"However, a longer commitment period places greater reliance on the accuracy of long-term forecasts of energy prices, demand, and the economy and thus can transfer price risk, or the uncertainty in such long-term forecasts, from suppliers to customers. Thus, a commitment period that is too long might encourage investment in capacity resources to meet or exceed targeted resource adequacy needs, but at the risk to customers that the investment becomes uneconomic either before or during the commitment period. In addition, locking-in capacity arrangements for a longer period necessarily results in fewer opportunities for customers to change those arrangements in response to changing market conditions, since they are committed to those capacity resources for a longer amount of time," Staff noted.
FERC Staff's report also includes discussion regarding the administratively determined demand curves for the capacity mandate. Of note, Staff said that:
"Using a downward-sloping demand curve also means that market outcomes are more heavily influenced by the administratively-determined CONE value. As Appendix B explains, calculating a value for CONE requires a number of estimations and assumptions that can be contentious. The choices made in these estimations and assumptions, and any errors in them, will impact the shape of the demand curve and the corresponding market clearing prices. Moreover, CONE (and the estimations and assumptions underlying it) must be updated at regular intervals (such as every three years as in NYISO), requiring sometimes lengthy and contentious stakeholder proceedings and litigation at the Commission. In addition, choosing the reference technology whose typical costs and revenues will form the basis for CONE could have a significant impact on the types of technologies that, in the long run, will be likely to recover their fixed costs, since the downward-sloping demand curve is ultimately designed to procure an amount of capacity equal to the planning reserve margin at a price of CONE over the long term" (emphasis added).
Link to FERC Staff Report
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