July 8, 2025
The Transmission Challenge Threatening SPP’s Renewable Energy Future
Author: Maha Mapara, Senior Energy Analyst, REsurety
Senior Energy Analyst, REsurety
Transmission congestion has become a growing issue over the last several years. As more wind and solar capacity has been installed in the U.S., delivery of least-cost energy to load centers has become increasingly difficult. Due to this, higher-cost energy is dispatched to meet the load requirements; driving up electricity prices for consumers, decreasing deliverability of cleaner energy sources, and decreasing grid reliability. In order to offset congestion-based revenue losses, grid operators and market participants can use financial instruments to hedge against congestion. This article focuses on Southwest Power Pool (SPP) to explore the impacts of congestion and how these impacts can be mitigated.
One of the major effects of transmission congestion is on electricity prices. Locational Marginal Prices (LMPs) determine prices in wholesale electricity markets. LMPs are dependent on location, supply, demand, and transmission constraints. When a transmission line is congested, it becomes economically less efficient to dispatch power across that line. This results in a higher LMP at the delivery point compared to the injection point (where generation is located). A congested transmission element, coupled with oversupply at the injection point can drive LMPs to low or even negative values for the generating wind or solar projects.
SPP is a Regional Transmission Organization (RTO) that serves approximately 18 million residents in all or part of 14 states. This wind-rich region has seen a large wind capacity expansion from ~16GW in 2017 to ~34GW in 2024. In 2017, SPP became the first operator in North America to serve more than 50% of its load at a given time using wind generation alone. Wind power has consistently been the largest single source of generation over the last few years, accounting for 37% of total generation in the winter 2025 quarter. Furthermore, comparatively lower installation costs and Power Purchase Agreement (PPA) prices than other U.S. regions position SPP as an attractive region for wind development.
However, the grid-system market value of wind energy in SPP is the lowest among all U.S. operators at $13/MWh in 2023. This represents a 60% lower market value for wind relative to average wholesale prices, driven by a combination of profile- and congestion-based value reductions. The congestion-based value reduction stems directly from inadequate transmission infrastructure.
The current infrastructure lacks the capacity to transmit the plentiful, low-cost wind energy typically located in rural areas to more distant urban demand centers. For example, many wind projects located to the west and north of Oklahoma City face ‘deliverability’ issues to the city due to transmission constraints. This creates significant price differentials between the point of generation and the point of demand, ultimately leading to revenue losses for wind projects on one end, and higher consumer prices on the other.
To quantify this issue in a simple manner, we can consider wind generation to be ‘deliverable’ if the price difference between the point of generation and Oklahoma City is less than 10%. The figure below shows a consistent decrease in the deliverability of wind energy from 38% in 2018 to 15% in 2024. At the same time, installed wind capacity in SPP increased by nearly 19GW, underscoring the disparity between wind generation and existing transmission capacity.
To address transmission constraints, SPP identified transmission system components, or ‘flowgates’, that experienced severe bottlenecks from 2022 to 2024. One of these flowgates is the Cimarron 345/138 kV XF 3 transformer, located just west of Oklahoma City. It is responsible for stepping down high-voltage power for local distribution and incurred over $50 million in congestion costs over the 24-month period. Several reasons contributed to this: multiple wind generators upstream producing at the same time, outage of other transformers at the same substation, and the connection of major new projects like the 998 MW Traverse Wind Energy Center in March 2022. As a result, the transformer became the most congested flowgate west of Oklahoma City by the fall of 2024. The economic impact of a constraint is measured by the shadow price, and for this flowgate, it reached a 12-month rolling average of over $60/MWh in the winter of 2025. This means that for every additional MWh of electricity that could have been transmitted through this bottleneck, the system would have saved $60 on average.
Given the significant financial impact of such congestion, market participants like utility companies and electricity suppliers often utilize financial hedging instruments to reduce their exposure. Financial Transmission Rights, also known as Transmission Congestion Rights (TCRs) in SPP, are instruments that function like an insurance policy; a TCR is purchased in an auction and provides its holder with a payout when there is a price difference between two points on the grid in the day-ahead market. Consider a simple example: a wind project in western Oklahoma experienced a $5/MWh nodal price, while the price in Oklahoma City was $70/MWh. If the wind project held a TCR between these two points, it would have received a payment for the $65/MWh price spread, minus the purchase price. This mechanism would have allowed the project to offset the revenue lost to congestion, thereby locking in more predictable earnings. However, in areas with chronic congestion, the cost of acquiring TCRs can escalate significantly, potentially making them prohibitively expensive or leading to scenarios where the purchase effectively locks in a loss for a project. Conversely, if congestion doesn’t materialize as anticipated, a TCR holder might have overpaid for their hedge.
The real-world impact of this hedging was evident in the SPP TCR market results for the winter 2025 quarter. Load-serving entities collectively earned $837 million through the congestion hedging market, more than covering their $707 million in day-ahead congestion costs. In contrast, other participants like generators and financial entities did not fully cover their total day-ahead congestion cost of $544 million. Nevertheless, hedging still proved beneficial, leading to a $341 million reduction in this total.
Ultimately, while financial instruments like TCRs provide a mechanism for managing the economic risks of congestion, they are a treatment for the symptom, not the cure. The persistent bottlenecks and declining deliverability of wind power in SPP underscore an urgent need for physical solutions. Recognizing this, SPP’s Board of Directors, in October 2024, approved $7.7 billion for 89 transmission upgrades. This investment includes 2,333 miles of new transmission and 495 miles of transmission rebuilds. Such efforts are expected not only to relieve congestion but also to enhance grid resilience and boost renewable investment in the region.
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