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In this article we explain how the shift from Fixed Volume Swaps (FVSs) to Virtual Power Purchase Agreements (vPPAs) — post the Texas Blackout Event in February of 2021 — might have inadvertently added new market risks.
Having just written about the April 28th collapse of the Spanish grid, it’s worth rewinding to another defining moment in the renewable energy era: the Texas ERCOT crisis of February 2021.
Five years later, most of the technical analysis is complete. But much of the financial and structural lessons are still largely unprocessed. In fact, some of the industry’s responses may have biased the market — swinging from one risk model to another without fully appreciating the tradeoffs.
ERCOT 2021 Case Study
• In February 2021, Texas experienced a historic winter storm (Uri), triggering extreme system-wide outages and price spikes, with real-time prices hitting the $9,000/MWh cap.
• Many generators, especially wind farms, underperformed due to icing and freezing of turbine components.
• Generators with FVSs faced catastrophic losses: while they generated little or no energy, they were still contractually obligated to pay the CFD on the full hedge volume — often leading to negative cash flows of tens of millions of dollars over just a few days.
• vPPAs, by contrast, limited financial exposure to actual production. Wind farms that underperformed had reduced exposure — but this came at the cost of lost upside during the high-price period.
• Key insight: volume mismatch, not just price spikes, destroyed value under FVSs. However, had the same generators had dispatchable capacity (e.g., batteries) to meet the fixed volume obligation, they could have captured enormous value.
• This triggered a market-wide reassessment of FVSs in all shapes and sizes, despite the fact that the issue was not the structure itself, but the absence of shaping capabilities.
How Renewable Hedge Contracts Work (and Fail)
Before the storm, renewable developers often relied on financial hedges to stabilize revenue. Two of the most common:
Fixed Volume Swaps (FVSs)
• The generator agrees to financially sell a fixed volume of energy at a fixed price, regardless of actual generation.
• If the market price rises, the generator owes the buyer the difference times the fixed volume, even if they don’t generate it.
• Useful when generation is stable — but dangerous when it’s not.
Mechanics:
• hedge_revenue = (hedge_price - floating_price) x fixed_volume This is the swap settlement for the fixed volume. You are locking in revenue on the fixed volume at the hedge price, receiving (or paying) the difference vs. the floating price.
• market_revenue = floating_price x floating_volume This is the merchant revenue from actually selling power at market price for whatever volume was generated.
• total_revenue = hedge_revenue + market_revenue
• Substituting… total_revenue = floating_price x (floating_volume - fixed_volume) + fixed_price x fixed_volume
• Rearranging terms… total_revenue = floating price x (floating_volume - fixed_volume) + fixed_price x fixed_volume
This last equivalency is important because it implies that the risk to the hedge is almost entirely born to the difference between the floating volume and fixed volume subjected to the floating price (first term). There’s little risk if the floating volume is above the fixed/hedge volume.
Unit-Contingent vPPAs
• The generator sells energy at a fixed price, but only on actual generation.
• If the generator doesn’t produce due to weather or curtailment, they owe nothing.
• If they produce during periods above the strike price, the owe back the difference between the nodal or hub price and the strike price. As long as prices are stable, there’s no issue.
• Seen as “safer” post-storm — but they tend to carry hidden risks.
Mechanics:
• If market price < strike price: → The buyer pays the difference to the seller (to guarantee the seller their fixed price). → The seller sells the power into the market and also receives the difference from the buyer.
• If market price > strike price: → The seller pays the difference back to the buyer. → The buyer makes money on the hedge (but they still pay their utility or retailer separately).
How FVSs Cracked in the Cold
Let’s walk through an example.
• Market price: $9,000/MWh (price cap)
• Hedge strike: $25/MWh
• Fixed hedge volume: 100 MWh/day
• Actual generation: 10 MWh/day (low wind)
Under an FSV:
• REVENUE = (Hedge strike-Market price)*Fixed hedge volume = (25-9000)⋅100=−$897,500
Under a unit-contingent vPPA:
• REVENUE = (Hedge strike-Market price)*Actual Generation = (25-9000)⋅10=−$89,750
Same market conditions, but 90% less financial exposure under a vPPA. That difference drove a wholesale shift in hedge strategy across the market after the storm. Simply put, too many RCP’s were overhedged at the wrong time.
The Great Migration to vPPAs
After the event, many developers, banks, and offtakers quickly moved away from Fixed Volume Swaps (FVSs), retreating to what they saw as safer territory. This shift was already in motion, but the incident accelerated it. The era of generous PPAs had ended, but independent power producers (IPPs) hoped that by capturing some of the price stability of traditional PPAs — even at lower compensation — they could mitigate the risks inherent in FVSs. As a result, a somewhat new financial swap — the unit-contingent vPPA, often with embedded basis clause — emerged as the preferred swap structure: more flexible, perceived as safer, and easier to finance. However, this transition brought new complexities, including intricate basis-sharing clauses to hedge congestion risk.
FVS vs vPPA — A Side-by-Side Comparison
Comparing risks between Fixed Volume Swaps with vPPAs is not trivial but can be made simpler by arranging and comparing the swap terms. We present this assessment for the reader in simplified terms to better understand the risks:
Below we present the risks in quantitative terms for a basis-contingent vPPA for more experienced energy analysts, data scientists, risk/credit analysts and the like. Note this reduces to a standard vPPA when the “alpha” value or buyer’s share of the basis risk is set to zero.
In the example above the basis risk for a hub-linked, basis contingent vPPA is higher than an FVS (see settlement formula) for two reasons:
• The actual volume on average for an IPP, tends to exceed its P90 seasonal volume estimate — from which the hedge volume linked to its P90 would be derived — this happens 90%+ of the time. Therefore the entirety of the volume is exposed to basis risk for a vPPA vs just the hedged volume for an FVS.
• The buyer’s share of the basis risk is added to the price for a vPPA thus increasing its volatility (i.e. basis-adjusted price whenever alpha > 0).
The Risk Shift: From Volume to Basis
What the market didn’t fully appreciate is that while basis-contingent vPPAs reduce volume risk for the buyer, they increase basis risk — the spread between nodal and hub prices.
As we have mentioned in previous articles, with growing renewable penetration, that spread is getting worse due to the following:
• Congestion is more frequent as transmission lags new generation
• Price volatility increases during stress events (e.g., cold/warm snaps combined with renewable under/oversupply)
• Nodal prices often diverge sharply from hub settlements
Because basis-contingent clauses within vPPAs apply to all generation vs just the hedged volume, basis risk affects the entire cash flow — and during grid stress, those spreads can become massive.
While virtual power purchase agreements offer a powerful tool for large energy users to invest in clean power, they come with a complex set of risks that need to be carefully managed. . (courtesy of verse.inc)
The Missed Opportunity: FVSs with Distributed Assets and Storage
What if, instead of abandoning FVSs, developers had improved on the overall concept?
Imagine pairing a fixed volume hedge with:
• Distributed or collocated storage (batteries, thermal, hydro, etc.)
• Distributed assets with uncorrelated output resulting in a portfolio effect.
• As mentioned in our previous write-up on the Spanish Grid Collapse, Solar and wind bids should be aggregated and structured with complementary assets (like hydro, batteries, or demand response) to create stable, dispatchable blocks as well as allow for participation in baseload supply.
• Better forecasting and telemetry across the entire renewable supply stack — technologies which are absolutely critical to managing the complex eco-system of distributed, highly variable generation.
You could reduce volume mismatch, firm the hedge, and command a higher strike price in the market — all while capping downside exposure.
This structure would retain the upside of FVSs without the fragility, offering:
• Better risk-adjusted returns
• Lower basis risk exposure
• More efficient capital deployment
In reality, an FSV with smart volume shaping can outperform a standard vPPA — especially in congested or volatile markets like ERCOT. This is what a Distributed Dynamic Hedge is designed to do.
Lessons the Industry Should (Still) Learn
The Texas storm exposed deep vulnerabilities in grid operations and FVSs— but also in financial strategy. Here’s what it taught us:
• FVSs are not inherently broken. They just need storage and smarter, distributed management.
• Basis-contingent vPPAs reduce visible volume risk, but hide others. Such vPPAs do not shield the risk from events where there is massive congestion.
• Basis risk and shape risk are now front and center. All indicators suggest they are increasing and will continue to do so well into the future. Such vPPAs contribute to the overall effect by shielding individual IPPs from volume-related obligation and associated financial losses in exchange for increased basis risks, all while displacing the volume uncertainty elsewhere into the grid.
• Firm hedges belong with firm or dispatchable capacity. The predictability of a fixed volume contract makes it much easier to schedule energy into the Day-Ahead and Real-Time markets.
• In contrast, basis-contingent vPPAs are tied to variable generation and require the grid to make adjustments based on the latest forecasted production. Unless price signals justify withholding or curtailing volume due to basis, Qualified Scheduling Entities (QSEs) who schedule on behalf of an IPP will bid right up (or down) to the most recent forecast — creating a dynamic, and often unstable, scheduling challenge. A sudden change in price well above the strike price, can effect the basis component of the swap contract resulting in negative forward revenue and sudden changes to volume output.
• The market sometimes overreacts to rare events. As a result, due to the transition away from FVS, vPPAs are now fueling renewable growth across the globe as well as new risks mentioned here.
• Forecasting and storage are still largely underutilized to match hedge volume.
• FVSs offer real hedge value if the risk is distributed — i.e. if storage is built into the contract, hedge design can match asset flexibility.
Concluding Remarks
The ongoing shift from Fixed Volume Swaps FVSs to basis contingent virtual vPPAs in renewable energy contracting has been shaped by market events, risk perception, and evolving grid dynamics. But the move away from FVSs may represent an overcorrection — one that sacrifices long-term grid stability for short-term contractual simplicity.
Basis-contingent vPPAs have grown in popularity because they offload volume and shape risk from the generator, require no volume forecasting commitments, and are perceived to be more “flexible” in the face of weather-driven variability. This has made them especially attractive to new entrants and intermittent generators like wind and solar developers.
However, that same flexibility introduces new risks — particularly basis risk and real-time dispatch volatility. Under a basis-contingent vPPA, an Independent Power Producer (IPP) bears the full basis risk, which becomes increasingly pronounced as grid congestion worsens. In response, IPPs and the Qualified Scheduling Entities (QSEs) who are managing the swap contract on their behalf often attempt to manage that risk by curtailing generation or shifting demand based on price forecasts alone. But real-time price signals are notoriously noisy and difficult to act on until just before market closure, forcing last-minute curtailment decisions that add complexity to grid operations.
FVS structures, in contrast, impose a firm delivery requirement, typically for a set hedge volume. This encourages proactive forecasting, shaping, and — where available — investment in storage. The result is a more disciplined approach to scheduling, which can benefit the grid, especially as renewable penetration increases. However, FVSs require more operational sophistication and come with their own risks, particularly when actual generation diverges sharply from the hedge volume.
In reality, neither structure is inherently better. Each has its place depending on the generation profile, grid conditions, and the sophistication of the offtaker and seller. Markets with high renewable variability and limited storage may benefit from the flexibility of vPPAs. Meanwhile, more mature assets with stable output or access to shaping tools may be better suited to FVSs. The real issue is not the presence of basis-contingent vPPAs — it’s their dominance in new contracting.
A healthy, resilient grid depends on a mix of contract types and on distributing the price risk among market participants. Over-reliance on any one structure — especially one that encourages last-minute dispatch behavior prior to market gate closure — risks amplifying the very challenges that markets like Spain and ERCOT have faced. As more renewables come online, grid operators don’t just need clean power, but power that is predictable, shapable, and responsive to demand.
Policy makers and energy buyers should encourage a portfolio approach to hedging. This means supporting contracts that incentivize firm delivery where feasible from a diverse fuel supply stack, while still offering flexible structures where appropriate. It also means recognizing that shaping technologies — like distributed storage — can enable more sophisticated load-following contracts without forcing projects into binary choices between flexibility and firmness.
What Comes Next?
As the grid continues to decarbonize, transmission lags, and basis spreads widen, the renewables sector must rethink hedge design from the ground up.
Smart developers will recognize that basis-contingent vPPAs are not always safer — they just move the risk somewhere else. The real winners will be those who:
• Integrate fully distributed storage in order to manage the volume risk component
• Model basis risk but *only for above a given pre-hedged volume — then curtail if too risky.
• Use forecasting intelligently to synchronize between distributed IPPs and storage in order to create a firm baseload supply of renewable energy.
• Design flexible, hybrid hedges, distributed across multiple assets.
The next wave of hedging innovation isn’t just financial — it’s operational. At Digital Wind, we aim to be a part of that transition.
