What does a higher reserve margin mean for the Southwest Power Pool?

What does a higher reserve margin mean for the Southwest Power Pool?
Feb 15, 2024

Tougher reserve requirement increases pressure on stakeholders while providing fresh opportunities for storage technology.

Concerned about the increasing penetration of renewables, especially wind with non-firm generation, the Southwest Power Pool (SPP) ISO has told utilities they need to ensure a wider buffer between available capacity and peak demand.

The decision to hike this reserve margin to 15% from 12% reflects important questions about the future of supply within SPP—where almost every major utility is forecast to fall short of capacity targets by 2027.

SPP oversees a huge swath of territory from northern Texas to the Canadian border. Covering 15 states, the Little Rock-based organization is tasked with ensuring reliable power and competitive wholesale prices for about 19 million people.

The rise of renewables

It’s a task that has become more difficult in recent years. Along with rising demand, SPP’s mix of power generation is increasingly shifting from conventional power supplies to more volatile renewables. Wind share in total generation has increased from less than 5% in 2010 to over 32% in 2023. Over 70% of new projects queuing up for connection today are either solar or wind.

While the rise in renewables—such as wind and solar—reduces greenhouse gas emissions, it can impact reliability when the wind isn’t blowing and the sun isn’t shining.

Figure 1 illustrates the scale of the challenges facing SPP today. The combined reserve margin across its territory had plunged from a comfortable 39% in 2015 to a little more than 22% last year.


This trend is expected to continue in the years to come, with the projected reserve margin forecast to slump to just 13.6% by 2027 as more sources of reliable power are retired (based on signed interconnection agreements which are on schedule and announced retirements).

A power imbalance

A deeper look into these numbers reveals additional challenges. Last year’s reserve margin of 22% refers to the total across all utilities in SPP’s territory—which means high margins among some individual suppliers are masking shortages of capacity among others.

The suppliers with the most comfortable reserve margins are also the smallest contributors of power to SPP, while the suppliers with the lowest margins are responsible for the bulk of load within SPP.

For example, the Kansas City Board of Public Utilities and Grand River Dam Authority boast high reserve margins of about 50% and 40%, respectively. But together they meet less than 3% of electricity demand in the SPP region.

Now consider the largest suppliers in SPP—American Electric Power (AEP), Evergy (Kansas City Power & Light Company and Westar Energy), and Oklahoma Gas and Electric Company—which together meet around 50% of the demand for electricity within the SPP.

As shown in Figure 2 below, all three are operating very near or below the reserve margin threshold.

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SPP Fig 2

The steady decline in the reserve margin over the years paints a potentially challenging picture for SPP, leaving them little breathing room in an industry vulnerable to unexpected failures of generation and spikes in demand.

SPP has taken a significant step with its decision to raise the reserve margin for individual power suppliers to 15%. Let’s consider what this new threshold means for stakeholders within SPP, beginning with the penalties for failure.

Penalty for noncompliance

The utilities and other suppliers within SPP—which are also known as Load Responsible Entities (LREs)—have already expressed concerns about not having sufficient time to achieve the new planned reserve margin (PRM).

Accordingly, SPP has brought in new rules that will apply temporarily for two years after any PRM increase. The applicable penalty for not achieving the PRM is determined by two factors: the existing reserve margin (RM), and a parameter called CONE (Cost of New Entry of a gas turbine), as shown in Figure 3. It could be as high as 2X of CONE, which ensures that it is more prudent for a utility to procure capacity in advance either bi-laterally or set up a new gas turbine, if necessary, rather than paying a penalty.

However, under the new rules, a sufficiency valuation curve is used. This may reduce the penalty from about $130/kW-yr as a “deficiency payment,” to approximately $50/kW-yr based on the forecasted 2023 RM of SPP.

This respite, however, will be short-lived, and the harsher up to 2X CONE penalty is expected to be in effect by 2027 after the two-year grace period expires and the reserve margin is expected to narrow to 13.6%.

SPP Fig 3

The next few years will be critical for SPP, especially with its biggest utilities facing the most challenging forecasts when it comes to future capacity. Overall, the tightening of capacity supply is expected to have four important implications:

  • Delayed retirements to provide sufficient time for new capacity to come online.
  • Higher resource adequacy prices.
  • Better re-contracting opportunities.
  • Construction of new capacity additions, mostly benefiting storage growth and possibly gas units supporting hydrogen fuel.

As Figure 4 reveals below, unless major utilities either procure new capacity or avoid retirements, they won’t be able to meet the new 15% threshold and be subject to penalties.

SPP Fig 4

Opportunities for storage

SPP may have a difficult road ahead as it tries to ensure that reliable power generation is available with ramping up of solar and wind, which are variable by nature. Their capacity accreditation is far below their nameplate capacity and decreases with increasing penetration. The wind capacity credit is already at a low range of 14%-15%, while the solar capacity credit is currently high but is expected to fall to around 37% by 2030.

Under these circumstances, and despite their high initial costs, battery energy storage systems (BESS) seem poised to benefit as they can provide the required reliability and allow utilities to reach the desired PRM.

SPP Fig 5

BESS can be set up quickly, tends to have a smaller footprint, and can be sited closer to transmission congestion centers. They can also be set up as hybrid units with existing solar or wind plants, allowing them to take advantage of brownfield sites. Most importantly, this would allow them to avoid the long generator interconnection queue of SPP by using the separate “Surplus Interconnection Queue,” as long as they limit their output below the parent plant’s interconnection limit as shown in Figure 5.

An analysis shown in Figure 6 found that the revenue curtailment due to interconnection threshold limit was less than 5% when co-locating a 100 MW battery facility with a 250 MW wind plant in windy northwestern Oklahoma, making co-locating a sweet proposition. The recently passed Inflation Reduction Act (IRA) has removed the constraints of charging battery banks, exclusively with solar power for availing investment tax credits (ITC), and made them available to both wind and grid charging, depending on the situation. This has opened new opportunities for storage in SPP, which leads the U.S. in wind penetration but has almost negligible solar penetration.

The supply constraint of firm capacity is expected to drive resource adequacy prices. Along with the significant arbitrage opportunities in SPP due to high wind penetration, the resource adequacy payments could give a boost to installation of BESS in SPP.

However, scaling batteries would come with challenges of their own. Storage has high initial costs, is still comparatively a new technology, and its degradation patterns have not yet been established at grid scale. There is also no certainty on the reserve contribution available to BESS co-located with other renewables, which can severely affect the important capacity revenue component.

Recommendations to minimize risk

SPP is hiking the reserve margin to address rising volatility with increased renewable penetration. Together with other steps like additional reserve ancillary products, this is an important step toward supplying adequate power at reasonable prices.

Here are three key recommendations to ensure stakeholders—such as utilities, independent power producers, and asset developers—are prepared for these changes:

  • Storage: Explore capabilities and revenue streams.
  • Supply mix: Identify optimal mix of energy sources to achieve low cost and reliability, including newer technologies like hydrogen-fueled gas turbines.
  • Existing thermal assets: Analyze capacity opportunities.

SPP's decision to increase the reserve margin is a proactive measure to combat the challenges of a changing energy landscape. While it presents significant challenges for utilities that they will have to overcome to meet the new requirements, it also opens up new opportunities in the marketplace.

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. 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

  3. Pradeep Podal, Manager, Energy Markets

    Pradeep is an energy expert with more than 15 years of experience spanning energy engineering to wholesale and retail U.S. power markets. View bio

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