The Clean Energy Buyers Association (CEBA), the industry association focused on activating energy buyers and partners to advance low-cost, reliable, carbon emissions-free global electricity systems, worked with REsurety to answer the question – “We know clean energy buyers make a difference in getting clean energy projects built. But how important are they, really?” The answer: the upfront contracts that clean energy buyers sign, called power purchase agreements (PPAs), have played a critical role in the buildout of clean energy in the United States. Read on to see CEBA’s press release and link to the report.
Companies that voluntarily buy clean energy play a critical role in clean energy projects being built. Without extensive voluntary commitments by corporate buyers to purchase clean energy, fewer projects will be financed and built, and the U.S. will struggle to meet growing energy demand.
Over the past decade, corporate clean energy procurement has accounted for more than 40% of new U.S. clean energy capacity additions. Corporate procurement enables companies to meet sustainability goals, hedge against unpredictable energy prices, and support the U.S. electricity grid’s expansion and resilience.
The U.S. is demanding more electricity than ever, driven by the rise in artificial intelligence, increased electrification, and resurgent U.S. manufacturing. To meet this demand efficiently and cost-effectively, the U.S. needs to build a lot more clean energy — and fast.
Why Is Corporate Demand for Clean Energy So Important?
A recent CEBA-commissioned study analyzed the scale of impact that corporate offtake provides. Until now, there have been limited data points to show the extent to which long-termcorporate virtual power purchase agreements (VPPAs) enable energy projects to get financed. This study shows how truly vital corporate offtake is in energy projects being built and bringing energy to the grid.
A VPPA is a financial contract between a company and a renewable energy project where the company agrees to buy the project’s power at a fixed price, but without taking physical delivery of the electricity, often contracted for 8-15 years. Corporate buyers guarantee a price for electricity, insulating the projects from the ups and downs of market electricity prices and making it possible for projects to get financing. This long price guarantee from the company gives lenders the assurance they need to provide capital for the project.
Without a corporate buyer, a project’s revenues are dictated by fluctuating wholesale electricity prices, also known as “merchant revenue.” Variability in merchant revenue can lead to periods where projects cannot meet their term debt obligations, resulting in financial distress. VPPAs – and, to a lesser, but still important, extent, renewable energy certificates (RECs) – are essential instruments to blunt these fluctuations.
VPPAs and RECs Provide Revenue Stability for Clean Energy Buyers
REsurety analyzed the economic performance of 251 wind and solar projects that operate in three major U.S. energy markets: ERCOT (Texas), MISO (Midwest), and PJM (Mid-Atlantic). Here’s what they found:
Corporate VPPAs slash financial distress by up to 90% in key markets: By hedging against dynamic market prices, VPPAs provided the revenue stability to reduce the number of projects facing financial distress by approximately 80% in ERCOT and over 90% in MISO and PJM compared to the merchant scenario. This stability is critical for securing project financing.
RECs reduce incidents of financial distress by up to 30%: While their impact is less substantial than VPPAs, unbundled REC purchases provide an additional revenue stream that can reduce financial distress compared to purely merchant projects. RECs do not directly mitigate wholesale power price volatility. However, higher REC revenue can lead to more significant reductions in financial distress.
Figure 1: Percentage of renewable energy projects that face simulated financial distress (defined as having a negative free cash flow) across different revenue scenarios in ERCOT, MISO, and PJM. The scenarios include revenue from the wholesale market only (Merchant), revenue from the wholesale market plus a $2.74 REC (With REC Offtake), and revenue from the wholesale market plus a VPPA (With VPPA).
Conclusion
Corporate clean energy agreements are essential to the financing and construction of the electricity generation we need. As the demand for electricity continues to surge and the grid requires rapid, cost-effective generation, the continued involvement of corporate procurement is more critical than ever to ensure the necessary clean energy build-out. As load growth continues, corporate participation and recognition are necessary to accelerate clean energy additions to the grid.
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.
Thank you to the Clean Energy Buyers Association for organizing a great spring summit in Minneapolis last week! It was a fantastic opportunity to reconnect with energy leaders and learn more about the current state of the market.
Here are five key takeaways that emerged from discussions with industry experts and innovators:
1. Speed to Capacity is Key
In today’s climate, electricity generation (of any form) is a national security and economic issue, not just a “renewables” issue. Renewables, storage, and gas (if you’ve already ordered a turbine, that is) are the fastest way to add the capacity to the grid that is needed to accelerate the data center development fueling AI.
2. Shifting Procurement Focus
In light of high costs and scrutiny on corporate budgets, corporate purchasers are exploring new options in addition to “traditional” greenfield vPPA strategies, including procuring clean power from operational projects, shorter terms (under 10 years), purchasing long-term REC strips, and working more with utilities for low-carbon power supply.
3. GHG Accounting Debate
The role of 24/7 clean energy in the Greenhouse Gas Protocol is being heavily debated, with concerns about feasibility, costs, data availability, and emissions benefits highlighting the need for practical approaches for carbon accounting. There is universal recognition that the incentives shaped by the Greenhouse Gas Protocol should empower companies of all shapes, sizes, and locations to take ambitious and meaningful climate action via a range of technologies.
4. Commitments Are Staying Firm – For Now
Despite some industry headwinds, it was exciting to see corporate buyers remain committed to their climate goals. That said, we caution against celebrating too early: buyers are working under increased budget pressure, so we are seeing more companies looking at ways to manage costs and risks carefully.
5. The Voluntary Market Has Been Expanding
The clean energy buyer ecosystem has been visibly expanding. Two directions of expansion include 1) companies relatively early in their decarbonization journey seeking “high impact” options for reducing emissions, and 2) larger organizations using their buying power on behalf of suppliers to decarbonize their supply chain (and associated Scope 3 emissions).
What were your top takeaways from the CEBA Summit? Let us know in the comments here.
The Greenhouse Gas Protocol (GHGP) is undergoing its most significant update since 2015, and the future of Scope 2 reporting is on the table. The GHGP is preparing to consider proposals and revisions to the existing market-based method, and key decisions are taking shape in technical working groups. Now is the time to understand what is being considered, how it could impact your organization, and how to get involved in the process.
This webinar hosted by the Clean Energy Buyers Association was the first in a series of webinars to explore the Scope 2 updates process from multiple perspectives. These webinars will unpack the most likely Scope 2 revisions scenarios and explore their potential implications for corporate procurement, emissions reductions, and broader decarbonization strategies. Markus Walther, CEBA’s Director of Global Clean Energy, Climate and Standards, moderated this first webinar discussion. Watch the recording below to hear from experts with insights into the ongoing working group discussions as well as buyers who shared real-world perspectives on how these changes could reshape decision-making and operations.
Watch the first webinar of this series below and understand the potential implications of Scope 2 revisions and learn how to effectively engage the Greenhouse Gas Protocol moving forward.
Hosted by CEBA, featuring speakers from REsurety, GM, Engie, and Baringa
Watch the recording of our recent webinar that explored the benefits and challenges of carbon matching in global decarbonization efforts. The upcoming revision of the Greenhouse Gas Protocol will redefine the future of clean energy procurement, and voluntary markets are crucial in allowing clean energy customers to continue to drive systemic grid decarbonization. Carbon matching is one strategy available to customers in facilitating reporting claims and driving clean energy projects worldwide.
This webinar delved into the basics of carbon matching and its benefits for customers in financing clean energy projects and reducing emissions, as well as the challenges of implementing this approach.
Speakers:
Alex Foster, Sustainability Solutions Manager, Engie
Robert Threlkeld, Director, Global Energy Strategy, General Motors
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