U.S. renewable generation installations have increased at a steady pace, driven by states’ clean energy targets (i.e., Renewable Portfolio Standards or RPS) and corporate sustainability goals. The rate of clean energy build has been higher than the expansion of the transmission grid under Regional Transmission Organizations’ (RTO) planning and interconnection processes. The result of renewable growth with limited grid capacity has led to extreme congestion in many areas of the country. Although renewable projects must complete interconnection studies to identify potential network upgrades required for reliable interconnection to the grid, these studies do not ensure that those generation projects will not be unduly impacted by congestion throughout their operations.
Transmission congestion can result in two main types of cost exposure for clean energy projects - curtailment and/ or basis - dependent upon a project’s contractual arrangements. Curtailment represents a reduction in a project’s energy output that cannot be delivered to the grid because of transmission limitations or simply because the market cannot absorb all the available supply of low-cost energy in a market interval. The emergence of Commercial & Industrials (C&Is) in the clean energy customer base over the last few years has led to more Corporate Power Purchase Agreements (PPAs), which are virtual contract-for-differences arrangements that require price settlement at a market hub. Under such arrangements, the generator typically wears the risk of any price differential between its point of interconnection and the market hub. This price differential or “basis” is typically and largely driven by transmission constraints between areas with renewable energy resources and the hub where load is concentrated.
Both the curtailment of clean energy generation and market congestion costs have materially increased across many RTOs over the last three years. For example, in their State of the Market 2021 report , SPP’s Market Monitoring Unit noted how monthly average curtailment increased from 136 megawatt hour (MWh) in 2019 to 725 MWh in 2021, an increase of over 400% in unused available clean energy. SPP congestion costs were also reported to have increased from $450 million in 2020 to $1.2 billion in 2021.
In this context of increasing, and sometimes extreme congestion levels across many regions, three main concerns arise regarding basis risk: (1) the ability to appropriately forecast basis risk; (2) the available mitigation strategies to reduce basis risk exposure, and (3) the contractual terms that are equitable considering 1 and 2.
(1) Forecasting Basis Risk
Sophisticated production cost simulation models that mimic nodal wholesale markets are typically used to project future basis risk. Detailed short- to medium-term assumptions are modeled to simulate market dispatch under future conditions. This is a standard approach to projecting basis risk and has given some assurance to vested parties that basis is appropriately assessed and forecast. However, the reality is that many drivers of basis risk are outside of a generator’s control – future siting and development of additional clean energy projects, grid outages, natural gas prices, future load and load patterns, etc. Uncertainty around these assumptions increases greatly beyond a 5-year forecast window. After this, it becomes very difficult to predict the exact location and size of future projects, as well as where, when, and for how long transmission outages will occur. Even natural gas prices, which have been relatively stable for many years until unprecedented events like the COVID-19 pandemic and invasion of Ukraine, have resulted in extreme price volatility that could persist for several years.
As an example of how unpredictable and extreme basis risk can suddenly become, we present below a chart of annual average system wind-weighted basis from MISO West generators to Minnesota Hub versus annual average wind penetration in MISO. The chart below shows that the MISO West grid reached a “tipping point” in 2020 when wind-weighted basis began to increase dramatically as wind penetration levels also increased. While MISO recently approved a Long-Range Transmission Plan consisting in $10 billion of new 345kv lines that will significantly increase the transmission capacity in MISO West, those upgrades are not expected to be completed until around 2030.
Average wind-weighted basis of all MISO West generator nodes to Minnesota Hub vs wind penetration over time (MISO West zones are defined as ALTW, DPC, GRE, MDU, MEC, MP, MPW, NSP, OTM, SMP)
A similar tipping point is observed in SPP, where annual average system wind-weighted basis from SPP generators to SPP South Hub has continued to trend negative starting in 2020.
Average wind-weighted basis of all generator nodes to SPP South Hub vs wind penetration over time (2022 is year-to-date through 8/9/22)
To further illustrate how quickly basis expectations can deteriorate in a market, comparing project-specific basis projections from 2017-2018 to actual basis levels today, shows a general under-estimation of basis risk by multiple dollars per MWh for many regions.
• For example, a 2017 third-party basis study for a Minnesota wind project forecast ($2.00-4.50)/MWh in basis to Minnesota Hub through 2021. By 2019, third-party Minnesota Hub basis projections for an Iowa wind project had increased to ($6.00-9.00)/MWh. While the 2019 study captured more congestion than the 2017 study with more wind on the system, both estimates have proven to be far short of the ($20.00-30.00)/MWh realized basis seen by many wind projects in MISO West today.
• ERCOT is another market where basis expectations for many existing projects were generally low outside known overbuild pockets (e.g., Texas Panhandle). For many ERCOT wind projects, industry basis cost projections for 2018-2020 were in the ($1.00-4.00)/MWh range. Stability-driven Generic Transmission Constraints (GTCs) now result in realized basis levels over ($10.00)/ MWh annually for many ERCOT wind projects, with some of these GTCs were implemented with little to no notice to market participants.
“With focused efforts at the FERC and RTO levels for more robust and comprehensive planning of the grid of the future, the transmission system will be more able to integrat large-scale renewables”
While these observations point to specific generator examples, current realized basis is several times higher than what was reasonably expected only a few years ago across wide areas. This can become especially detrimental for a project when these basis costs are higher than the fixed price a project receives in its offtake contract. Across many regions with high congestion today, comparison of actual versus projected conditions generally demonstrated that key variables driving the higher than predicted basis were: (i) lagging transmission system expansion compared to regional or local renewable build in the area, (ii) grid outages, which can further limit grid capacity and last for many months, and (iii) new constraints or at times sudden derates of grid facilities, further lowering the capacity of the grid. None of these variables can be predicted with strong level of confidence on the long term.
(2) Mitigating Congestion-Driven Basis Risk
There are some congestion mitigation options available, but each provides only a partial solution. A few examples are discussed below:
• Financial Transmission Rights (FTRs) are fixed-cost financial instruments, with clearing prices that typically follow congestion trends and settle on the day-ahead congestion component of basis in monthly, seasonal, or/and annual auctions. As such, FTR congestion coverage can only offer partial basis mitigation, providing a net benefit only if realized congestion costs are higher than the cost of the instrument.
• Sponsored upgrades are transmission upgrades paid for by a market participant who voluntarily agrees to fund the cost of an upgrade to obtain some relief in expected congestion. While such upgrades could help address a specific constraint, they can be very expensive and there is no guarantee that the relief will be permanent. Other generators can saturate the additional grid capacity with new generation or different constraints could become binding (aka, the “Whac-A-Mole” constraint game) – which would offset the basis improvement from the sponsored upgrade.
• Grid Enhancing Technologies (GETs) such as topology optimization, dynamic line rating, and advanced power flow controllers can be deployed to maximize the capacity of the existing grid at relatively little cost. Although GETs can be implemented - within short lead times - as temporary, bridge or permanent solutions to many transmission constraints, they are yet to be considered on a broad basis absent better processes and incentives to boost their deployment.
• Improved transmission planning processes including via a more comprehensive assessment of longer-term transmission needs can fundamentally mitigate the basis risk. The Federal Energy Regulatory Commission (FERC) has begun reforms in this area, which are critical to the clean energy transition, especially given the long lead time required for transmission upgrades. A new 345kv backbone line can easily take 7-10 years to be permitted and built. The identification of needs must thus occur earlier than the materialization of extreme congestion as seen often in the history to date.
While the factors above can contribute to a reduction in basis, they do not warrant sufficient protection against high and sustained congestion. There remains a risk of severe congestion driven by grid outages or mismatches between generation and transmission expansion.
(3) Contractual arrangements on basis risk
Replace - The current extreme congestion levels across several areas of the grid demonstrate that, despite sophisticated modeling tools and some opportunities for mitigation, clean energy generators face high basis risks whose costs can be much worse than initially anticipated. Faced with this reality, both clean energy buyers and sellers should be mindful of intrinsically high basis risk and find ways for more equitable risk sharing in offtake structures. A contractual standard that puts uncapped basis exposure on generators is inefficient and inequitable given that generators have no control over key drivers of basis risk. The complexity and magnitude of basis risk has been poorly understood in the industry, but this cannot continue. Going forward, negatively skewed basis risk must be acknowledged in transactions and shared accordingly. When risks are borne by on parties that don’t have the ability to respond and optimize, it is suboptimal for the system. Not only that, but congestion-driven basis risk can ultimately turn out to be one of the biggest obstacles to a successful clean energy transition.
In brief, increased transmission congestion levels observed across many RTOs highlight the unprecedented basis risk in what has become a typical offtake structure for clean energy projects. The complexity and uncertainty of uncapped basis exposure , as well as the unprecedented challenge of expanding the transmission system to keep up with large-scale deployment of clean energy projects, require a more realistic and equitable sharing of basis risk in contractual arrangements with market hub settlement. With focused efforts at the FERC and RTO levels for more robust and comprehensive planning of the grid of the future, the transmission system will be more able to integrate large-scale renewables, reducing basis risk which in turn will make sharing this risk less of an industry headwind in the fight against climate change.