Making sense of MISO’s recent capacity auction

Making sense of MISO’s recent capacity auction

In our pre-auction paper, we made three predictions about the 2022/23 Planning Resource Auction (PRA) based on our analysis of pre-auction data:

  1. Prices would be higher than in the previous auction ($20-30/MW-day vs. $5/MW-day) due to higher demand and lower supply.
  2. MISO North (Zones 1 to 7) would clear at a common price, but Zones 4 to 6 would remain tight in local supply and rely heavily on imports; we also acknowledged that they may set high clearing prices if the region has insufficient local capacity and/or low-cost imports are not available.
  3. MISO South (Zones 8 to 10) would clear separately due to the sub-regional export constraint.

While the second and third of these predictions were borne out by the auction results, the first prediction did not capture the extent of the price increase in MISO North. In MISO North, prices ended up reaching the price cap, or the Cost of New Entry (CONE) of $237/MW-day, whereas MISO South cleared separately at $2.9/MW-day. This article explains this outcome, as well as other key results, such as bidding behavior, import dynamics, and the resource mix that cleared the auction. We conclude by assessing whether the auction results are anomalous or indicative of deeper resource adequacy trends in MISO.

This post-auction analysis is based on currently available information. As new information becomes available, our views may evolve, and we will update the analysis as appropriate.

Prices spiked in MISO North as capacity offers declined and demand increased

Based on the pre-auction data, we expected higher prices in MISO North given increases in demand and tightening supply, especially in Zones 4 to 7, which have historically relied on imports to meet their Planning Reserve Margin Requirements (PRMRs). These zones were expected to rely more heavily on imports to meet their PRMRs due to lower offered capacity driven by retirements, capacity de-rates, and general capacity withholding from the PRA. However, in our base case, we did not expect a capacity shortage that would cause prices to reach the CONE of $237/MW-day. The capacity shortage was caused by a 1.4 GW higher PRMR and 3.7 GW less offered capacity in this auction compared to the last auction (Exhibit 1). Nearly 90% of this capacity decline was seen in MISO North, with a 2.8 GW decline in Zones 4 and 5 alone (Exhibit 2).

As a result, offered capacity was 4.5 GW lower than the PRMR in MISO North (96.7 GW vs. 101.2 GW), which could not be met by the 1.9 and 1.3 GW of imports from MISO South and the External Resource Zones (ERZs), respectively. While overall imports increased compared to the previous auction, they did not offset the decrease in local capacity and increase in demand, and total committed capacity in MISO North remained around 1.2 GW lower than the PRMR. MISO South had excess capacity to export, but it was constrained by its sub-regional export limit of 1.9 GW and cleared separately at a low price ($2.9/MW-day). Without this export limit (or with an unconstrained offer curve), MISO North would have cleared at around $65/MW-day, which is still significantly higher than the $5/MW-day price in the previous PRA.

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Exhibit 1: Differences between 2022/2023 PRA and 2021/2022 PRA results

Exhibit 1: Differences between 2022/2023 PRA and 2021/2022 PRA results

Exhibit 2: Offered capacity in the 2022/23 PRA vs. ICF expectations and 2021/22 PRA results

Exhibit 2: Offered capacity in the 2022/23 PRA vs. ICF expectations and 2021/22 PRA results

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Non-merchant offers decreased while merchant offers increased

We also observed changes in bidding behavior. Compared to the 2021/22 auction, there was a roughly 6 GW decrease in self-scheduled and Fixed Resource Adequacy Plan (FRAP) capacity, which is usually offered at near-zero prices. This decrease caused the share of self-scheduled and FRAP capacity to decline by four percentage points (Exhibit 3a). Furthermore, there was a 6 GW increase in high-price merchant offers; merchant capacity as a percentage of total cleared capacity increased to 8.1%, compared to 4% to 5% in the previous auctions (Exhibit 3b). The most significant increases in merchant capacity were observed in Zones 1, 4, 5, and 6. This impact can also be seen in the offer curve, which shifted leftward as zero price bids decreased (Exhibit 4). MISO’s Minimum Capacity Obligation (MCO) proposal, submitted to FERC, could limit further shifts. The MCO would require LSEs to procure at least 50% of their PRMR ahead of each PRA. MISO justified this proposal by noting that a small number of LSEs increasingly rely on the PRA for capacity procurement and that the MCO would prevent overreliance on PRA.

 

Exhibit 3a: Self-scheduled and FRAP capacity

Exhibit 3a: Self-Scheduled and FRAP Capacity

Exhibit 3b: Merchant capacity as % of cleared capacity

Exhibit 3b: Merchant capacity as % of Cleared Capacity

Exhibit 4: Unconstrained offer curves for 2020/21, 2021/22, and 2022/23 PRAs

Exhibit 4: Unconstrained Offer Curves for 2020/21, 2021/22, and 2022/23 PRAs

Only the LSEs with net short positions prior to the PRA are exposed to high prices       

Load serving entities (LSEs) in MISO have traditionally procured most of their capacity needs outside of auction through self-supply or contracts, with the PRA acting as a balancing market for additional capacity. The high clearing price in MISO North will only apply to the amount of capacity that LSEs procured from the PRA to meet their load obligations. In MISO North, there is nearly 8 GW of such capacity, which constitutes around 8% of total cleared capacity. As shown in Exhibit 3a, nearly 92% of total cleared capacity was either self-supplied or contracted.

All zones in MISO North cleared at a single price

While Zones 4 to 7 could not meet their PRMRs, all zones were able to meet their LCRs. This was due to high-capacity import limits and lower LCR-to-PRMR ratios for Zones 4 to 6 such that none of these zones were constrained due to their LCRs. However, MISO North as a whole was short of capacity. In contrast, in the 2020/21 PRA, only Zone 7 cleared separately at the CONE ($257/MW-day) as it was short of local capacity to meet its high LCR (99.6% of PRMR); other zones in MISO North cleared at a lower price ($5/MW-day).

Increasing reliance on natural gas and renewables

The share of coal capacity cleared in the PRA continues to decrease with corresponding increases in the shares of natural gas and renewables (Exhibit 5). Over the last five years, the coal capacity share has decreased from 36% to 30%, whereas the total share of natural gas and renewables has increased from 39% to 46%. These trends are expected to continue in future PRAs due to planned coal retirements and the predominance of renewables among new builds. However, renewables (especially wind and solar) have limited capacity accreditation. For example, for 1 GW of firm unforced capacity, the system would require nearly 7 GW of wind or 2 GW solar based on their current capacity credits.

 

Exhibit 5: Historical cleared capacity mix in MISO PRAs

Exhibit 5: Historical Cleared Capacity Mix in MISO PRAs

Implications of the auction results for the future of MISO resource adequacy

Are the high prices in MISO North in this auction an anomaly or a representation of deeper forces at play in MISO? We conclude the latter, particularly due to changes in the capacity mix in MISO North. In 2023, we expect over 8 GW of retirements and only 3 GW of new capacity (derated for renewables) across MISO. Unless there is a reassessment of unforced capacity and planned retirements, transmission expansion, or a sufficiently large increase in long-duration storage builds, shortages could persist in future auctions.

Due to these potential shortfalls, there is an increasing need to reform the MISO resource adequacy construct to provide proper economic signals. Price stability in the MISO capacity market should be a key aim of this reform to induce the necessary investment. One potential reform that would reduce volatility is the use of a sloped rather than vertical demand curve. The MISO Independent Market Monitor has estimated that if a sloped demand curve had been used in the 2021/22 PRA, the price would have been $150/MW-day as opposed to $5/MW-day. Nevertheless, we expect that utilities will try to limit their exposure to the volatility of the auction by increasing self-supply and bilateral contracts. This will put upward pressure on bilateral contract prices.

Finally, due to capacity shortages, emergency events, and the predominance of renewables among new builds, proper capacity accreditation is necessary to maintain system reliability. One potential reform in this area that has been proposed by MISO is the use of availability-based resource accreditation based on the top 5% tight margin hours in each season. MISO's proposal is currently under evaluation by FERC. Other potential reforms in this area that are being considered by MISO include hybrid capacity accreditation, seasonal and monthly outage modeling, and forward capacity accreditation for renewables.

 
Meet the authors
  1. Vinay Gupta, Senior Manager, Energy Power Markets

    Vinay is an energy market expert with more than 10 years of experience in techno-economic modeling and analysis of the U.S. energy markets, focusing on ERCOT, MISO, and SPP markets. View bio

  2. Dinesh Madan, Director, Energy Power Markets

    Dinesh Madan joined ICF in 2005 and has been extensively involved in the areas of energy market modeling, wholesale power market assessment, asset valuation and financial modeling, and restructuring and litigation support including contract evaluation and risk assessment.   View bio

  3. George Katsigiannakis, Vice President, Energy Power Markets

    George is an expert in U.S. electricity markets with a deep understanding of all factors affecting U.S. wholesale electric markets including market design, environmental regulations, fuel markets, transmission, renewable, energy efficiency, and demand side management. View bio

  4. Ian Bowen, Energy Markets Analyst