Navigating the Hub-Node Gap with Creative Contracting.
There is no single price of electricity in the United States. While the price of a barrel of oil is set nationally, electricity is set locally – and fluctuates based on grid mix, time of day, and many other factors in a given region. As we’ve discussed in our Forecasting Webinar and our recent blog on the impacts of Venezuelan oil on clean energy prices, all energy market dynamics are interrelated. So when it comes to deciding whether to build or invest in a clean energy project like a solar or wind farm, the difference in electricity prices by region, and volatility in price over time, make all the difference for project success.
What do local price dynamics have to do with a solar farm’s ability to pay back its loans over time? The devil is in the details. And the details are called basis risk.
Background: The US electricity system’s hub + node structure
The US electricity system is made up of tens of thousands of nodes, where load and generation connect to transmission and distribution lines to form a giant, interconnected grid. A node may be a single solar plant, a collection of gas turbines, a datacenter, or a substation feeding thousands of homes. Each of these nodes has its own power price.
Groups of nodes are organized into hubs. Hubs are virtual trading points, where the price is the average of all the nodes within the hub. (An example of a hub)
Most power purchase agreements (PPAs), where corporates or utilities agree to long-term contracts to buy power, are settled at the hub. Every month, the contract is settled by calculating how much money the developer would have made from selling their power to the grid at the hub price, how much money the developer is guaranteed by the PPA signed with a corporate or utility buyer, and “settling” the difference. If market prices were low one month at that hub, the buyer sends the developer money to get them to their guaranteed PPA revenue. If prices were high one month, the developer sends the buyer the extra money that came in the door.
In this article, we’ll walk-through an example of a real project and make the math behind settling clear. We’ll show how risk is shared between developers and buyers, and how to share risk to increase success.
Basis risk puts revenue at risk: real world example
Let’s look at a wind project in SPP South, at an anonymous location in Oklahoma. For this project, and many others like it in the region, node prices were often lower than hub prices in 2025, exposing the developer to basis risk. Let’s make the following typical assumptions about the project to determine the impact of basis:
The project has a PPA that settles at the hub
The fixed PPA price is $20/MWh
The project curtails (stops generating) for when hub prices are below $0/MWh (i.e., negative)
Bad basis reduced project revenue by over 60% in 2025
As shown above, the developer made roughly $0.6M in January from the PPA after settlement (blue line), with some variation month-to-month based on their total generation (i.e., how hard the wind blew). However, they lost roughly $1.3M in January due to large negative basis (red line, caused by nodal prices being below hub prices), leaving them at a loss of roughly $0.6M (yellow line) for the month. The negative basis continued until August, leaving the developer with $4.4M less revenue in 2025 than they earned from the PPA, a 65+% drop. This erases any profit margin for the project, leaving it deep in the red and at risk of defaulting on loans.
Despite this wind project performing very well, the developer can’t meet financial goals – putting the PPA at risk. Shouldn’t there be a way to share risk between the developer and the corporate purchaser to avoid this issue?
The answer is yes – and folks are getting creative with how. One option is to settle at the node, but this passes all risk to the buyer. Another option is to share basis risk between developer and buyer, which can require complex modeling & contracting. REsurety’s services team helps customers with these questions all the time.
Contract clauses are one of many solutions to navigating a changing grid
As the grid continues to change, a tailored, risk-mitigating approach like basis sharing is essential for supported long-term financial health of clean energy projects. These clauses protect developers from bankruptcy and ensure the continued generation of RECs for the offtaker, making them a balanced and increasingly common feature in modern PPAs.
Stay tuned to learn more about typical contract clauses to share basis risk between developers and buyers, and to learn more about additional approaches to solve basis risk like on-site BESS, behind-the-meter datacenters, and financial transmission right (FTR) trading. Until then, if you need advice on your current basis clauses – reach out!
Master the PPA Market: Critical Insights for High-Stakes Decision-Makers.
Many clean energy market participants benefit from transparent PPA pricing data, including clean energy buyers, sellers, developers, producers, and financiers. This data is critical to better understand their investments, assess the viability of projects, negotiate competitive contracts, and plan effective and resilient decarbonization strategies. REsurety, as the leading provider of clean energy software, services, and marketplace solutions, works closely with market actors to bring purpose-built tools and expertise to their every decision. When S&P identified the need for real-time, trustworthy PPA market insights to fuel their price assessments – REsurety was the clear partner.
The New Era of Clean Energy Procurement: Certainty Amidst Volatility In a market defined by shifting tax credits, supply chain disruptions, and evolving GHGP standards, “good enough” data is no longer an option. Tight margins are the new reality, and the window to execute before costs climb is closing.
REsurety + S&P Global: Transparency You Can Trade On We are proud to announce a pioneering partnership with S&P Global Energy. By combining REsurety’s exclusive CleanTrade transactional data—the first CFTC-approved marketplace—with Platts’ world-class price assessments, we are delivering a level of price certainty previously unavailable to the US PPA market.
Don’t Just Advise. Execute. While others sound the alarm, we provide the tools to navigate it. Whether you are hedging operational PPAs or sprinting toward new offtake agreements, our advisory team leverages deep analytics and real-world transaction volume to secure your clean energy future.
Empower your team with the data-driven insights needed to manage risk and maximize the impact of your clean energy portfolio. Speak to REsurety today to turn market complexity into a competitive advantage.
We’ve been monitoring the 2026 Venezuela intervention closely to understand its impact on domestic natural gas markets.
Why?
Because the price of crude oil ripples through the entire energy complex, ultimately dictating the financial health of renewable energy contracts.
Let us take a moment to explain.
Global oil production has an indirect yet significant influence on gas availability—specifically through “associated gas” produced in U.S. oil fields. A natural byproduct of drilling for oil is natural gas – It’s a “package deal”—you can’t extract the oil without releasing the gas. According to the U.S. Energy Information Administration (EIA), this byproduct now accounts for approximately 40% of total U.S. natural gas production.
This vast supply of low-cost associated gas serves as the primary fuel source for the thermal plants that set the market-clearing price for power. Because electricity prices are so tightly coupled to these fuel costs, any fluctuation in the natural gas market—driven by global oil trends—becomes a primary driver of long-term power price forecasts, including WeatherSmart forecasts like REsurety’s.
How the ramp up of oil production takes place in Venezuela will make a difference for the future of the clean energy market by shifting the economics of producing, selling, or buying PPAs.
While change is coming, it’s not arriving overnight. According to recent analysis from Rystad Energy (January 2026), returning Venezuela to its peak production of 3 million barrels per day would require a staggering $183 billion in investment and would not be fully realized until 2040.
REsurety has created three scenarios about future energy prices in the new world order, what this means for clean energy, and trigger moments to watch for along the way – read on to learn more.
A blip in long-term prices, or a market shift?
The current plan to release 30–50 million barrels of seized oil provides a cyclical impact. Cyclical changes are temporary price swings driven by immediate supply-demand imbalances or short-term geopolitical events. These movements are mean-reverting, eventually returning to a historical baseline once the disruption passes. This temporary inventory flush (roughly two days of U.S. consumption) may dampen prices for a few weeks but does not alter long-term capacity.
While the release of seized oil may have a cyclical impact, there are more system-altering forces at play. The broader developments in Venezuela represent a fundamental structural shift in the energy landscape.
Structural changes represent fundamental shifts in the market’s underlying framework. For example, the rapid scaling of grid-scale storage has permanently changed how the grid manages peak demand, establishing a “new normal” from which the market does not return.
In the case of Venezuela, this is a long-term strategy to establish a lower global price floor. We have identified three potential scenarios through which this transition may reshape natural gas benchmarks and, consequently, downstream PPA capture rates – or revenue earned from PPAs.
The most likely of the scenarios is “Crude-Driven Supply Contraction,” which is the best case scenario for the clean energy PPA market. In this scenario, Venezuela’s oil industry internationalizes — driving down oil prices and in so doing, inadvertently drives the price of natural gas up as the U.S. cuts back on drilling. Clean energy sources look even better in comparison, and investment into clean energy should follow. On the other hand, a world in which the U.S. reacts to Venezuela oil production with its own ramp up in production could be difficult for clean energy: with energy prices at a low, the business case for investment in clean energy — or any energy source — may look less favorable.
Source: REsurety analysis.
REsurety’s Power Markets team, led by Mark O’Brien, is following this topic closely. Reach out to learn more about the impacts on your business.
Scope 2 rules are changing, and the ripple effects will hit every corner of the clean energy market. If the current trajectory continues, buyers will face higher costs to meet their goals. Developers may need to structure offtake contracts differently. Investors will likely be asking new questions about value and risk.
When accounting rules change in any market, the effects cascade through all market participants – starting with the companies doing the accounting, but rippling through everyone in the value chain. REsurety’s data and analytics bring clarity to clean energy contract value and risks under a range of accounting rules, so you are working from a clear foundation no matter how the market evolves.
Now let’s take a closer look at the potential changes coming to Scope 2 accounting — and what’s at stake for your business.
Understanding the upcoming Scope 2 revisions
Scope 2 emissions are associated with purchased electricity, which is often treated as essentially synonymous with grid-based electricity use. Under the current market-based accounting method, procured clean energy — through unbundled RECs or bundled PPAs — is assigned against electricity consumption and counted as zero emissions, regardless of when and where the clean energy generation happened. So the net emissions reported only reflect emissions from the remaining balance of grid-based electricity use.
Now the Greenhouse Gas Protocol is revising Scope 2, with new standards expected to come into force in 2028. Though voluntary, the Protocol is the standard used for 97% of corporate disclosures, so the incentives created by the Protocol will shape corporate purchasing activity, which in turn will impact investors and project developers.
Two distinct Scope 2 proposals are on the table:
Hourly matching (24/7 carbon-free energy [CFE]). Matching consumption with clean generation in the same grid, in each hour of the day. The theory behind this approach is that same-hour, same-location matching will result in more accurate claims about plausibly consumed electricity. In other words: it’s easier to be accountable when the project is on the same grid, and if the energy was generated at the same time as it was consumed. This approach encourages the purchases of clean energy close to load, and – because of the constant balancing required to match consumption and generation – is expected to drive more activity in the spot market rather than long-term purchase agreements (such as PPAs).
Consequential emissions accounting. Some refer to this as “impact accounting” as well. Rather than attempting to match megawatt-hours of electricity usage or consumption, this approach measures the emissions impact of electricity usage/generation – such as induced emissions from load, or emissions avoided by clean generation – and adds up those impacts. The resulting incentive for a corporate buyer is to focus on clean energy procurement in the dirtiest grids, not necessarily the areas closest to their load. This approach offers lower cost implementation thanks to increased flexibility, more effective decarbonization, and also encourages the long-term purchases of power that drive global impact.
At the moment, it looks like hourly matching will be required as part of future reporting rules, and consequential emissions accounting will be a parallel reported metric. Here, we’ll focus on hourly matching, given it looks more likely to be a required part of future reporting standards.
Turning Scope 2 challenges into opportunities
As Scope 2 rules evolve, companies will need to navigate rising costs, new technologies, and shifting market dynamics. But these challenges also create opportunities for careful planning and smart strategies to make a real difference.
Challenge #1: Rising costs
Most studies agree that hourly matching will result in higher costs. If hourly matching becomes a requirement, increased costs will come from i) the need to buy zero or low-carbon power in times and locations when it is scarce, and ii) meaningfully higher transaction and management costs to matching of clean power and consumption. Auditing costs will also likely increase, as the volume and complexity of data required increases significantly.
So, think about your portfolio and business goals: How much clean energy will you need to buy over the next five or ten years? What is your current portfolio of purchases, and how does that leave you exposed in a changing accounting environment? In which hours and locations are you most likely to be long/short relative to your forecasted load, and what will the cost be to close those gaps partially or fully? How much will external risks – such as hourly weather variability or a changing power market supply stack – impact your carbon claims?
The time is now to start asking these questions. We are seeing a race for procurement of good projects as buyers scramble to lock in favorable contracts that will be “grandfathered in” before accounting rules change. In addition, even though the rules don’t take effect until 2028, large projects like a data center or a multi-year renewable deal take years to develop – making now the time to start planning.
Solution: REsurety can help you optimize spend
We know the rules, we know the policies, we know the markets – and we share your goals. We can talk dollars and cents to help you make the right decisions for your clean energy purchasing strategy.
For example, we helped one of the world’s biggest tech companies evaluate the cost of various strategies to meet their emission reduction goals through clean energy procurement: hourly matching, annual matching, and consequential carbon matching. We laid out the impact in multiple scenarios and the financial costs of each strategy.
The work helped leadership within the sustainability, finance and procurement functions of the organization to understand the cost / benefit analysis with each path, clarifying what each decision would mean for the overall business. In the end, we helped bring clarity to energy purchasing, enabling them to move forward a plan with a view on expected costs, ensured alignment with sustainability goals, and reduced financial risk.
Challenge #2: It’s going to require new solutions – from hardware to systems design
Some corporate clean energy buyers will need to consider new generation or reporting technology to meet new accounting requirements which may impact emissions goals. This might include diligence of new technologies (such as battery storage or carbon capture), optimizing renewable integration, or improving reporting systems.
If the GHGP Scope 2 rules go toward CFE/hourly time-matching, demand will rise for non-intermittent resources (i.e., dispatchable fuel types – like storage, nuclear, geothermal, and gas with carbon capture & sequestration [CCS]). For traditional thermal generation like natural gas power plants, if carbon capture is added, there would be a dramatic reduction in emissions that would flow through to companies that buy power from those resources.
Solution: REsurety can help you understand and de-risk new technologies
REsurety helps evaluate and implement the right technologies for your portfolio.
For example, using technology to foster around-the-clock low-carbon power is a strong complement to renewables. Our consulting practice recently worked with an organization to evaluate CCS technology at a large cogeneration plant, considering the technology from a range of angles (emissions considerations, carbon accounting limitations / benefits, time-to-value, comparison to next best alternatives, etc.). As natural gas-fired generation expands its role as a critical flexible resource to enable load growth, understanding new solutions like CCS will become more important.
Challenge #3: The voluntary market will shift
Corporate buyers, who voluntarily procure clean energy to offset their emissions footprint, are critical to new clean energy projects getting built. Long-term offtake agreements in the form of virtual power purchase agreements (VPPAs) or REC purchase agreements provide increased revenue stability to the project, thereby enabling access to critical project finance. Our recent analysis for the Clean Energy Buyers Association (CEBA), shows just how important this clean energy purchasing has been in the past: corporate voluntary clean energy purchases were shown to reduce project financial risks by up to 90%.
There is growing concern that a scenario where buyers must purchase hourly clean energy within the grid region where they operate – as hourly 24/7 would require – would make it harder for big corporations to make long-term contractual agreements. Why invest in an expensive and complex long-term agreement if you can’t use all of the resulting power for sustainability claims (due to inevitable hourly mismatch between generation and your consumption)? The business case quickly erodes. As a result, many people expect that hourly matching accounting rules will drive the market away from long-term offtake agreements and towards a short-term, hourly spot market. This will require projects to secure alternative means of offtake to fill the gap left by corporates (and it’s a big gap: 41% of US offtake over the past decade was driven by corporate purchases). New approaches to active portfolio management contracting structures and risk allocation approaches will be required.
Solution: REsurety gives you the tools for active portfolio management
The era of “set it and forget it” long-term PPA management is over, and a shift to hourly matching will accelerate that transition. Buyers, sellers, and traders are now actively engaging in shorter-term portfolio management trades to manage the exposures associated with long-term PPAs. Our team helps buyers evaluate portfolio management strategies – ranging from brokered spot market purchases, to a blend of long-term and short-term purchases, to crafting strategic long-term commitments. After setting a strategy, buyers and sellers can execute transactions on CleanTrade, the only federally regulated marketplace for clean energy. It provides near real-time data on projects that are available for purchase or sale, and liquidity/transparency needed to act quickly in response to changing demand requirements and market conditions.
Turning change into opportunity
Scope 2 is entering a new chapter. The rules are still being written, but one thing is clear: data-driven strategy is more important than ever. Paying attention now will put you ahead down the line.
REsurety was built for moments like this. With the right data and strategy, you can align budgets, manage risk, and make credible carbon claims. Whether you’re deciding how to buy, where to site, or which claims to make, we help you act with confidence and ensure your portfolio meets your business goals.
At the end of the day, our vision is simple: more clean energy, period. Let’s get your portfolio ready now so when the rules land, you’re already where you need to be.
Any statements of fact are derived from sources believed to be reliable, but are not guaranteed as to accuracy, nor do they purport to be complete. No responsibility is assumed with respect to any such statement, nor with respect to any expression of opinion which may be contained herein. The risk of loss in trading commodity interest derivatives contracts can be substantial. Each investor must carefully consider whether this type of investment is appropriate for them or their company. Please be aware that past performance is not necessarily indicative of future results.
The United States is currently entering an era of rapid electricity demand growth, fueled by increased electrification, onshored manufacturing, and an influx of data centers powering the artificial intelligence (AI) boom.1 This increased demand for electricity requires large amounts of new generation capacity — and renewable resources offer the fastest, most cost-effective path to adding new capacity.2
One of the key drivers of renewable energy growth over the last decade has been the voluntary renewable energy market, which encompasses energy procured outside of state clean energy mandates.3 Corporate buyers, in particular, have contributed significantly to voluntary procurement, signing over 100 GW of clean energy deals between 2014 and 2024, which represents 41% of all clean energy capacity added to the U.S. grid in the last decade.4 While corporate procurement represents a dominant portion of the voluntary market’s sales volume, other forms of offtake are also available (e.g., utility PPAs and green tariffs), though their sales volume is generally smaller in comparison.5
Clean energy procurement enables corporations to meet their sustainability goals and offset their electricity usage with zero-carbon, clean energy. Traditionally, corporate clean energy procurement has focused on wind and solar projects (which are the focus of this paper), but companies are increasingly signing agreements to procure firm generation from storage, nuclear, and geothermal projects.6 As more and more companies pledge to reduce their carbon footprints,7 offtake agreements, such as virtual power purchase agreements (VPPAs), serve as an effective way for companies to meet their decarbonization targets without needing to significantly alter their operating models.8 Offtake agreements can also serve as a hedge against the buyer’s electricity costs as a secondary benefit.9,10 In return, these fixed-price offtake agreements offer renewable energy developers a steady revenue stream, which enables them to attract the capital required for construction of their projects.11
Despite the clear impact that voluntary corporate energy procurement has had on renewable energy growth, its contributions to the energy transition are being questioned. Several recent studies and articles challenge the impact of these corporate actions, arguing that wind and solar technologies are so inexpensive (or subsidized by government policies) that they will get built regardless of corporate offtake.12,13 In reality, the primary role of corporate offtake agreements such as VPPAs is not to bolster clean energy technology, but to mitigate the financial risk associated with earning revenue from the variable wholesale electricity market.
In contrast to fossil fuel generators, wind and solar projects have low operating costs but relatively high capital expenditures14 that are financed through a combination of sponsor equity, tax equity, and back leverage debt. Once a project becomes operational, it must repay these upfront costs through term loans and dividends to investors. During periods of low wholesale power prices, projects may not earn enough merchant revenue to meet their debt service obligations or their investors’ rates of return, which, absent additional revenue sources, could lead to financial distress and potential default. Offtake agreements like VPPAs significantly reduce the likelihood of projects entering these periods of financial distress by providing projects with a fixed price for the energy they produce. It is for this very reason that offtake agreements make it significantly easier for projects to get financed and built; debt interest rates and required debt service coverage ratios are typically lower for projects with offtake,15 and the vast majority of projects built recently had some form of offtake agreement in place.16
In this paper, we put numbers and data behind the important role that corporate procurement plays in reducing the financial volatility of wind and solar projects in the United States. Using empirical analysis, we show that even when the net revenue earned from a contracted VPPA is negligible, the revenue-stabilizing impact of the VPPA significantly reduces the likelihood that a project will face financial distress. We also examine the impact of unbundled Renewable Energy Certificate (REC) purchases on renewable energy projects, finding that while RECs are less effective in reducing financial distress in comparison to VPPAs, the stable contracted revenue from REC purchases can make a significant difference for many projects during periods of low wholesale power prices. Our findings support the critical role that corporate procurement plays in getting clean energy projects financed and built — and highlight the continued importance of corporate procurement in an era when the grid needs more cost-effective generation.
Methodology
To assess the impact of voluntary corporate procurement of VPPAs and RECs on securing the financial stability of renewable projects, we modeled…
The United States is currently entering an era of rapid electricity demand growth, fueled by increased electrification, onshored manufacturing, and an influx of data centers powering the artificial intelligence (AI) boom.1 This increased demand for electricity requires large amounts of new generation capacity — and renewable resources offer the fastest, most cost-effective path to adding new capacity.2
One of the key drivers of renewable energy growth over the last decade has been the voluntary renewable energy market, which encompasses energy procured outside of state clean energy mandates.3 Corporate buyers, in particular, have contributed significantly to voluntary procurement, signing over 100 GW of clean energy deals between 2014 and 2024, which represents 41% of all clean energy capacity added to the U.S. grid in the last decade.4 While corporate procurement represents a dominant portion of the voluntary market’s sales volume, other forms of offtake are also available (e.g., utility PPAs and green tariffs), though their sales volume is generally smaller in comparison.5
Clean energy procurement enables corporations to meet their sustainability goals and offset their electricity usage with zero-carbon, clean energy. Traditionally, corporate clean energy procurement has focused on wind and solar projects (which are the focus of this paper), but companies are increasingly signing agreements to procure firm generation from storage, nuclear, and geothermal projects.6 As more and more companies pledge to reduce their carbon footprints,7 offtake agreements, such as virtual power purchase agreements (VPPAs), serve as an effective way for companies to meet their decarbonization targets without needing to significantly alter their operating models.8 Offtake agreements can also serve as a hedge against the buyer’s electricity costs as a secondary benefit.9,10 In return, these fixed-price offtake agreements offer renewable energy developers a steady revenue stream, which enables them to attract the capital required for construction of their projects.11
Despite the clear impact that voluntary corporate energy procurement has had on renewable energy growth, its contributions to the energy transition are being questioned. Several recent studies and articles challenge the impact of these corporate actions, arguing that wind and solar technologies are so inexpensive (or subsidized by government policies) that they will get built regardless of corporate offtake.12,13 In reality, the primary role of corporate offtake agreements such as VPPAs is not to bolster clean energy technology, but to mitigate the financial risk associated with earning revenue from the variable wholesale electricity market.
In contrast to fossil fuel generators, wind and solar projects have low operating costs but relatively high capital expenditures14 that are financed through a combination of sponsor equity, tax equity, and back leverage debt. Once a project becomes operational, it must repay these upfront costs through term loans and dividends to investors. During periods of low wholesale power prices, projects may not earn enough merchant revenue to meet their debt service obligations or their investors’ rates of return, which, absent additional revenue sources, could lead to financial distress and potential default. Offtake agreements like VPPAs significantly reduce the likelihood of projects entering these periods of financial distress by providing projects with a fixed price for the energy they produce. It is for this very reason that offtake agreements make it significantly easier for projects to get financed and built; debt interest rates and required debt service coverage ratios are typically lower for projects with offtake,15 and the vast majority of projects built recently had some form of offtake agreement in place.16
In this paper, we put numbers and data behind the important role that corporate procurement plays in reducing the financial volatility of wind and solar projects in the United States. Using empirical analysis, we show that even when the net revenue earned from a contracted VPPA is negligible, the revenue-stabilizing impact of the VPPA significantly reduces the likelihood that a project will face financial distress. We also examine the impact of unbundled Renewable Energy Certificate (REC) purchases on renewable energy projects, finding that while RECs are less effective in reducing financial distress in comparison to VPPAs, the stable contracted revenue from REC purchases can make a significant difference for many projects during periods of low wholesale power prices. Our findings support the critical role that corporate procurement plays in getting clean energy projects financed and built — and highlight the continued importance of corporate procurement in an era when the grid needs more cost-effective generation.
Methodology
To assess the impact of voluntary corporate procurement of VPPAs and RECs on securing the financial stability of renewable projects, we modeled the economic performance of 251 operational wind and solar projects across ERCOT, MISO, and PJM. These markets were selected due to their heavy concentration of corporate procurement; nearly 70% of future corporate procurement is forecast to take place in ERCOT, MISO, or PJM.17 While not covered specifically in this analysis, the modeling methodology and key findings are broadly applicable to other ISOs and markets outside the United States as well.
For each project, we simulated economic performance by calculating operating income and debt obligations using historic generation, price, and operating cost data from 2015 to 2024, then identifying sustained periods of financial distress. We compared the results to rates of financial distress in purely merchant scenarios of the same projects to quantify the stabilizing effect of corporate offtake.
While actual VPPA and REC prices, VPPA terms, and finance structures are highly project-specific, we used generalized characteristics that were derived based on industry reports and standards in this analysis. This approach allowed us to compare projects across different regions and time periods at scale, focusing on standard hub-settled VPPAs, which aren’t an effective hedge against price volatility for projects with high amounts of basis.18 In practice, many projects that experience continued, large hub-to-node basis will either renegotiate their hub-settled VPPA, sign a nodal VPPA, or include basis- sharing provisions in their VPPA contract to limit financial impacts to both VPPAs.19
Generation and Power Prices
First, we created a time series of hourly generation for each wind and solar project. We exclusively used observed generation for ERCOT projects, as ERCOT provides extensive generation data for both wind and solar projects. For PJM and MISO, we used proprietary REsurety modeled generation, which is calculated from a mixture of modeled weather data and project-specific characteristics.
For modeled solar generation, we applied a standard solar degradation rate of 0.5%20 for each year post-commercial operation date (COD). We simulated economic curtailment by using a nodal price threshold below which generation was reduced to zero. In reality, the breakeven price, below which production will be curtailed, for a renewable project will depend on the project-specific revenue streams it earns beyond merchant revenue (e.g., REC purchases). However, for the sake of simplicity and generalization across projects and markets, we used nodal price thresholds of $0/MWh for solar projects and –$27.50/MWh for wind projects, which assumes investment tax credit for solar projects and the full value of production tax credits for wind projects.
We calculated wholesale, or “merchant,” revenue by multiplying each project’s hourly generation time series by hourly averaged real-time nodal prices.21 Some projects will, in reality, have settlements that depend on day-ahead prices, but we assumed purely real-time settlement to maintain a generalized merchant methodology. We removed all ERCOT prices and generation from February 2021 due to the extreme volatility of the period as a result of Winter Storm Uri.
VPPA and REC Prices
Projects with an offtake agreement in place have an additional revenue stream beyond merchant revenue. In the case of a VPPA, settlement to the project is a function of the difference between a fixed VPPA price and the floating hub price. For a project with relatively low hub-to-node basis, the floating hub price is strongly linked to merchant revenue.
To focus on the risk mitigation benefits of the VPPA, we set the VPPA price such that the settlement of the VPPA over the lifetime of the contract was $0. Using this approach ensures that the simulated VPPAs don’t serve as a subsidy or a driver of revenue loss for projects — but instead, provide value purely by mitigating project revenue volatility.
We calculated the net revenue earned by a project with a VPPA as:
We compared the assumed VPPA prices against the market cost of energy and PPA prices from multiple sources, including Berkeley Lab Market Reports,22,23 Lazard LCOE+,24 and CRC-IB MCOE25 reports, to ensure that they aligned with and did not exceed industry benchmarks.
While RECs are typically bundled with VPPA contracts, clean energy buyers can also purchase unbundled RECs without a contract for power (e.g., a PPA or VPPA) in place. Corporate energy buyers may be interested in purchasing unbundled RECs as they are highly liquid instruments, allowing a corporate entity to purchase RECs flexibly as needed.26 For some companies that have sustainability goals but do not meet credit or contracting standards, REC purchases offer a more accessible alternative because of their lower requirements compared to a long-term VPPA. REC payments are made to the project on a per megawatt-hour basis and serve as a supplement to merchant revenue.
We used a REC price based on the historic price of the National Green-e® Certified REC Any Technology. Green-e® is the leading certification program in North America and represents a national and fuel-agnostic REC. We used a REC price of $2.74, representing the average REC price in 2023.27
Debt Sizing
Debt sizing is typically calculated based on numerous project-specific factors. To estimate a standard set of project debt obligations in this analysis, we calculated debt based on the project’s net operating income, sized to a debt service coverage ratio (DSCR). DSCR is defined as the ratio of net operating income to debt service payment, such that a project with a DSCR below 1.0 has negative cash flow and is in financial distress. Therefore, all debt providers require a DSCR above 1.0 at P50 revenue, but the range of specific values is wide and depends on individual project factors. Norton Rose Fulbright28 lists DSCR ratios ranging from 1.25 to 1.8, depending on technology and contracted status. We used a DSCR ratio of 1.5 as it is representative of an average project, so it can be applied broadly to the many projects evaluated.
To calculate debt obligations, we first estimated monthly net operating income for each project as revenue minus operational expenditure. We calculated operational expenditure as the mid-range value presented in Lazard’s 2023 LCOE+ report:29 $10.50/kW-year for utility-scale solar and $27.50/kW-year for onshore wind. We added a 2.25% annual escalation rate from the project’s COD.
To calculate a project’s debt obligation, we determined the average annual revenue for each project and sized the debt such that the average DSCR was 1.5. To ensure our derived debt estimates were aligned to market conditions, we also calculated the total loan amount by assuming a 20-year amortized loan with a 5.86% interest rate. The assumed interest rate was based on the 90-day average of SOFR30 rates + 150 basis points as of May 2025, which follows ranges provided by Norton Rose Fulbright for construction-derived term loans. We then compared this total loan amount against the calculated project capital expenditure31 to ensure that loan amounts fell within reasonable coverage ranges.32 These ranges were taken to be 10%–40% of total capital expenditure for wind and 10%–50% for solar. If a project’s derived loan coverage fell outside these ranges, we adjusted the loan amount, and therefore monthly payments, to bring the project into range.
Calculation of Financial Distress
Financial distress was defined as net operating income falling below debt servicing obligations (DSCR < 1.0). Due to the inherent variability of renewable energy generation and the volatility in market prices, most projects will experience at least one month where net income is below debt servicing; however, projects maintain cash reserves to manage short-term volatility that can address these brief debt service shortfalls. To account for these cash reserves, we used 24-month rolling sums of net operating income and debt service to calculate the DSCR over rolling two-year periods. By removing the variability of any one given month, we found cumulative two-year intervals where a project was unable to meet debt obligations and highlighted periods of sustained financial distress.
Analysis
After establishing the generation, VPPA and REC prices, and debt sizing for each project, we calculated the merchant revenue volatility experienced by the wind and solar projects in ERCOT, MISO, and PJM. We then quantified the impact of VPPAs and unbundled REC contracts on reducing that volatility and decreasing the likelihood of financial distress.
Volatility of Merchant Revenue
Merchant renewable energy projects in the U.S. have historically experienced significant revenue volatility. Offtake agreements mitigate this volatility by providing a steadier revenue stream, reducing financial distress during periods of low wholesale power prices.
Merchant revenue volatility is exemplified in Fig. 1, which shows the 12-month rolling average of generation-weighted nodal prices across ERCOT, MISO, and PJM for the selected projects. All three markets demonstrate similar macro trends: low prices in 2020 due to decreased demand during the COVID pandemic, high prices in 2022 due to elevated natural gas prices, and lower prices in 2024 due to falling gas prices and mild weather. These swings in prices lead to a high amount of merchant revenue volatility — in the last two years alone, the average value of renewable projects in PJM has ranged from $30/MWh to over $70/MWh. For a 100 MW project with a 40% capacity factor, this translates to a swing in annual merchant revenue from $10.5 million to over $24 million.
Figure 1: 12-month rolling average of generation-weighted nodal price for renewable projects in ERCOT, MISO, and PJM
Impact of VPPAs and RECs in Reducing Financial Risk
As shown in the previous section, the volatility of merchant power prices can cause large swings in renewable merchant revenue, highlighting the importance of having a steady revenue stream. While VPPAs reduce this volatility by hedging against low wholesale power prices, unbundled REC purchases provide a consistent revenue boost to projects that may otherwise experience financial distress.
The frequency of simulated renewable project financial distress is shown in Fig. 2 for a purely merchant scenario, a scenario where projects sell 100% of their energy through unbundled REC purchases, and a scenario where a fully contracted VPPA is in place. Even with a relatively low REC value of $2.74, REC offtake agreements reduce the amount of projects that would face financial distress from 38% to 18% in ERCOT (a 52% reduction), with reductions of 23% and 17% in MISO and PJM, respectively. VPPA agreements have an even greater impact on reducing the frequency of financial distress due to their hedging behavior. VPPAs reduce the amount of projects that would face financial distress in ERCOT from 38% to 9% (an ~76% reduction), with reductions exceeding 90% in MISO and PJM.
Figure 2: Percentage of projects (including wind and solar) that face simulated financial distress across ERCOT, MISO, and PJM. Distress rates are separated by revenue source, and high basis projects have been removed from all revenue source aggregations
We attribute the difference in impact between VPPAs and REC purchases to the difference in risk that each structure mitigates from the project. In essence, a REC purchase provides a low-risk revenue stream to the project that can blunt the effect of wholesale price volatility but does not address the underlying volatility itself. In some cases, the additional stable revenues earned by REC sales are sufficient to improve total cash flows above levels of financial distress. However, as shown in Fig. 1, wholesale power prices can be dynamic, and for many projects, the value of solely an unbundled REC is insufficient to mitigate financial distress.
Although we chose a specific REC value, that of National Green-e® Certified RECs, due to its wide adoption, availability, and common usage, more expensive RECs certainly exist. For example, PJM Tri-Qualified RECs have historically sold for up to $39, but are less commonly sold as unbundled, voluntary RECs compared to Green-e®. Not surprisingly, higher valued RECs provide larger contracted revenue relative to market power prices and fluctuations, resulting in significantly greater reduction of distress. We found that increasing the REC price to $7.50 resulted in a >75% reduction in distressed projects in ERCOT compared to the fully merchant scenario, with reductions of 70% and 50% in MISO and PJM, respectively.
Case Study
To demonstrate the impact of an offtake agreement on a more granular level, we highlight the impact that a VPPA has on revenue stability for a single wind project in PJM. We have selected an approximately 200 MW wind farm in Illinois due to its large capacity and long operational history. It is representative of the general revenue trends we see across markets — namely, merchant revenue that tracks overall market prices and VPPA net revenue that remains relatively level throughout the operational life of the project (Fig. 3).
Over the two-year period from 2018 to 2020, the project’s merchant operating income dropped below its debt service obligations, which would have caused financial distress (Fig. 3). However, the fixed price of the VPPA was higher than the market prices during this period, providing valuable revenue to support cash flows and help the project meet its debt service obligations, despite 12+ months of negative merchant cashflow. The same scenario has occurred again in recent months due to lower prices in 2024.
Due to the inherent risk mitigation of a VPPA, the project misses both the ups (2021–2022) and downs (2019–2020) of the market. Although an uncontracted project would capture merchant revenue upsides, which can be enough to avoid financial distress for 29% of projects in PJM (Fig. 2), the revenue stability gained from avoiding volatility risk makes it significantly easier for projects to get financed and built.
Figure 3: Simulated free cash flow (Net Operating Revenue – Debt Service) performance of a 200 MW wind project located in Illinois (PJM)
Summary and Conclusions
The United States is consuming more electricity than at any other period in history, and its need for energy output is only growing. Driven by a booming data and AI industry, manufacturing, and grid electrification, nationwide electricity demand is expected to increase by nearly 16% in the next five years after remaining relatively flat for several years.33 Due to their relatively low cost, ability to deploy rapidly, and environmental benefits, wind and solar energy are critical to meeting this demand growth.
In this paper, we demonstrate the crucial role that VPPAs play in providing financial resiliency to projects. Rates of financial distress for renewable projects would be significantly higher were it not for the revenue-stabilizing impact of VPPAs, making offtake agreements a crucial part of project financing. Projects that rely on purely merchant revenue are beholden to shifting market power prices and sustained periods of low prices, which can result in the fundamental inability of merchant projects to cover their debt obligations, limiting their access to capital. Purchases of unbundled RECs from renewable generators also increase the stability of their cash flows and, depending on the credit price, can produce a significant reduction in the frequency of financial distress.
In contrast to recent assertions, our results indicate that offtake agreements are critical to ensuring the revenue stability required to secure financing. Without extensive voluntary purchase of clean energy by corporate buyers, fewer projects will be financed and built, and the U.S. will struggle as a result to meet growing energy demand.
As we enter a period of rapidly declining federal support for climate goals and clean energy build-out, renewable projects will require the financial support of predictable revenues more than ever. Projects that no longer qualify for federal tax credits are expected to experience levelized cost of energy increases exceeding 30%,34 making it significantly more expensive to construct new projects. Corporate procurement is already a key component of financing renewable energy projects, but with the accelerated decline of federal tax credits, corporate offtake has become even more crucial for ensuring new projects can get built and remain financially viable.
At REsurety, our research and power markets team is dedicated to modeling energy prices, project generation, and emissions impact. The team is interdisciplinary: we have experts in power markets, statistics & analytics, meteorology, and grid operations.
Why do we need such a deep bench of experts? Because forecasting electricity prices is notoriously complex. These values determine what projects get built, sold, and invested in – months before we’ll know whether the wind will blow or the sun will shine. It’s high stakes, and our goal at REsurety is accuracy.
If you’re an energy buyer, we know better forecasts mean better budgets – helping you to engage internal stakeholders, build confidence in your portfolio strategy, and plan for future investments.
If you’re an investor, better forecasts help reduce uncertainty around whether projects will hit their rate of return or lead to stable, long-term yields.
And if you’re a trader, credible data means hedge providers can more accurately price offtake agreements. Improved pricing means better risk management with an eye towards the bottom line.
With so much in play, we take this job very seriously, and invest resources internally to focus on providing the analytics our clean energy customers need to lead. Often, it pays off: in July, for example, REsurety predicted ERCOT prices in the mid-$30s per MWh – and we were only off by one dollar. That doesn’t seem all that impressive unless you compare to market forwards: this spring, when we made this prediction, the market forecast predicted prices around $60/MWh – double actuals. Without REsurety data, buyers may have assumed twice what they received in revenue.
So, how were our forecasts that accurate? It boils down to our unique approach and our commitment to a weather sensitive, fundamentals-based model.
How We Optimize Our Models: Customer-First Thinking
Let’s take a step back to talk about our customers for a second. Our customers are looking to buy, sell, or trade clean energy. Take this example: a buyer is looking to enter into a PPA from a solar farm in their region, with a specific budget and generation capacity in mind for the year. When that customer uses REsurety price forecasts, they are not only looking for good data to value the solar power for sale right now against other solar assets, but also looking to compare against a baseline price provided by their grid operator – i.e., if they just pulled power from the grid, at whatever energy mix the grid operates at, and didn’t make the clean power investment at all.
Whether the purchase of solar power – from that specific solar asset – will “pencil out” is based on what its electricity is expected to sell for in the future. This price determines their clean energy buyer business case, and determines key financial metrics like payback period and cashflow volatility. For some corporations, if the renewable energy isn’t at price parity with traditional sources offered by the local grid operator, they won’t be able to buy due to budget constraints. Other companies have more flexibility, but often, our clients are working hard to justify their clean energy purchasing year to year, just like every other department at a company.
So with that in mind, our primary goal is to provide an accurate distribution of clean energy prices with actionable insights for our clients, recognizing their goals. We are not incentivized to inflate our prices for one side or another; we’re incentivized to help our customers keep making, using, and buying clean energy.
Our Fundamentals-Based Approach: The REsurety Difference
Forecasting electricity prices is tricky. In a grid like ERCOT, with significant intermittent energy generation sources from solar and wind, the task is even trickier. Weather, a significant and inherently difficult variable to account for, is a main driver of price forecasts.
Many traditional methods, like time-series and statistical models, often fall short. They struggle to meaningfully incorporate extreme weather events which are expected but only happen very rarely. This weather variability issue is exacerbated as the volatility and fundamentals of the market change as it grows. For a dynamic market like ERCOT, which is prone to short-term price spikes and has cases of extreme weather events such as 2021’s Winter Storm Uri, statistical models are particularly ill-suited.
Instead of relying on finding a causal signal in historical data, we employ a sophisticated fundamentals model. This model simulates how a market operator would dispatch supply to meet demand, providing a realistic view of market dynamics. While our point estimates don’t aim to perfectly predict every short-term spike, we acknowledge their possibility through our Weather-Smart distribution of prices. This distribution allows us to illustrate a range of potential outcomes based on various weather scenarios.
Our Advantage: Calibration and Pragmatism
Our forecasts are built on a foundation of robust data and expert analysis including publicly available market data, such as ERCOT’s own forecasts for load and generation evolution, our own market research & expertise, and comprehensive weather data.
This means that we don’t blindly accept forecasted load and capacity growth. Our model is continuously refined as the grid evolves, with improvements focused on areas like transmission constraint accuracy, granularity of generation additions, and impacts of policy changes.
Our advantage lies in our pragmatic approach to calibration:
Supply Must Meet Demand: We operate under the crucial assumption that grid capacity will be able to meet demand the vast majority of the time. This means that our expert team interprets various data points – such as the 300 GW of data centers in load interconnection queues across the country – and, rather than accepting them at face value, judiciously calibrates them to ensure that the result is a functioning power system.
Supply will be Built Out in a Realistic Way: We don’t assume that the supply chain can work to instantly build generation to meet unrealistic demand forecasts. Instead, we consider the practical realities of construction and project approval rates. If an ISO, like ERCOT, forecasts an unprecedented demand increase, and historical data shows such rapid build-outs are improbable, we factor that into our projections. We analyze interconnection queues, understanding that only a fraction of proposed projects actually come online.
Generation Source Behavior Matters: We meticulously examine the commitment and dispatch of specific generation types under different weather scenarios. For example, if wind saturation increases, we assess whether this realistically leads to a reduction in gas peaker commitment and, consequently, lower prices.
How REsurety’s Accuracy Drives Your Strategy
We incorporate weather variability to capture the short- and medium-term volatility in times of stress for the grid. This pragmatic, data-driven approach empowers you to:
Make Informed Decisions: Improve your understanding of when to buy and when to sell energy.
Improve Budget Forecasting: Achieve more accurate and reliable energy cost projections, empowering your financial planning.
Navigate the Clean Energy Market: Our forecasts help you understand the evolving dynamics of clean energy trading, even if you’re not an “energy nerd.”
At REsurety, we provide our customers with forecasts based on complex energy simulations and power markets expertise, giving them the insights they need to make informed investment decisions and navigate the energy market with confidence.
Want to learn more? Check out more resources from REsurety here.
REsurety is hosting a VIP customer event at the CEBA Spring Summit
Please join us at The Fortunate Prospector for a REsurety-hosted reception on May 22nd at 7:00 pm. The Fortunate Prospector is located in the Gaylord Rockies Resort & Convention Center. The REsurety team is looking forward to having a fun and engaging customer event. RSVP directly with your account executive.
Thank you for your interest in REsurety’s new paper, Emissions Implications for Clean Hydrogen Accounting Methods. Use the buttons below to download the full paper as well as an Excel spreadsheet containing the Locational Marginal Emissions data and hourly renewable energy generation data that was used for the analysis done in the paper.
REsurety and WattTime have made historical marginal emissions data available to qualified end users including researchers, corporate sustainability practitioners for accounting, and other non-commercial end users at no cost. This improves on the temporal and spatial granularity of the global annual country-level marginal emissions data already available from the UNFCCC.
You may request up to five free reports.
Please fill out the form and we will be in touch to discuss your request.
Company Overview: Products, Capabilities and Experience
Download the REsurety Company Overview Brochure to learn about REsurety’s product and service offerings, who our clients are and what they’re saying, and how REsurety enables the industry’s decision makers to thrive through market intelligence, asset insight, and the tools for action.
A recent white paper from REsurety, with contributions from HASI (fka Hannon Armstrong), a leading investor in climate solutions, offers an in-depth analysis into how using an “8760” energy model can lead to significant errors in revenue modeling — topping 30% in some high renewable penetration markets.
Despite their widespread use in the renewable energy industry, using an 8760 to project financial performance can lead to significant errors in revenue models. In particular, revenue models that pair an 8760 with historical prices miss the impact of hourly renewable energy generation on hourly power prices. Because wind and solar plants are relatively inexpensive sources of generation, there tends to be a negative correlation between generation and power price in markets with high renewable penetration.
A recent white paper from REsurety, with contributions from HASI, a leading investor in climate solutions, offers an in-depth analysis into how using an “8760” energy model can lead to significant errors in revenue modeling — topping 30% in some high renewable penetration markets.
An “8760” (also known as a “typical meteorological year,” or “TMY”) is the average generation expected for a given wind or solar project for each of the 8,760 hours in a non-leap year. As implied by its “typical meteorological year” moniker, an 8760 contains average generation values reflecting typical seasonal and diurnal weather patterns. The problem with using an 8760 is that “typical” weather isn’t actually all that common, and high prices almost always coincide with extreme weather.
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