If you work in corporate clean energy procurement, you may have come across the term “green tariff.” Green tariffs provide a pathway for businesses – particularly those in regulated electricity markets — to purchase renewable energy credits or renewable energy from their utility providers. This blog provides a quick overview of what green tariffs are, explores the various options available for corporate buyers, and lists a few key elements corporate buyers should be aware of.

What Is a Green Tariff?

Many corporate clean energy options involve a company contracting with a project developer or private-sector company for Renewable Energy Certificates (RECs) or for both the energy and the RECs through a virtual power purchase agreement (vPPA). A green tariff, on the other hand, is administered by a utility directly and allows commercial and industrial (C&I) energy users to purchase RECs or bundled energy and RECs. Green tariffs are most common in regulated electricity markets where clean energy mechanisms such as vPPAs are unavailable, but they may sometimes be available in deregulated markets.

Types of Green Tariffs

Because green tariffs are utility programs, they can vary widely between regions and utility providers. That means companies with operations in different utility territories or electricity markets may need to work with multiple green tariff mechanisms.

There are a variety of tariff options to meet different corporate clean energy procurement needs and goals. The common thread is their purpose: to help companies without access to mechanisms like virtual PPAs take advantage of renewable energy resources and attributes. Despite the variety, most utility green tariffs fall into one of two buckets: REC-Only tariffs, and subscription tariffs.

REC-Only Tariffs

As the name implies, REC-Only tariffs enable utility customers to take advantage of RECs. A regulated utility may have its own renewable resource (e.g., a solar farm in its territory), or it may contract with a renewable developer to buy a PPA. The utility can then offer customers the green or financial benefits from the RECs associated with those resources. Customers of regulated utilities typically pay for these RECs in the form of an additional fixed fee, or rider, on their electricity bill.

Retail utilities that want to offer RECs to corporate customers will typically buy unbundled RECs in the open market and sell them to customers with a slight markup to cover program administration cost.

REC-Only tariffs tend to offer more flexibility for corporate customers because they have shorter contract terms (typically a year) and are often payable as an additional fee on an existing bill. The REC mechanism is simple and does not require significant expertise to contract. RECs do not need to come from additional (i.e., new) renewable energy resources. For those reasons, REC tariffs are generally better suited to smaller corporate utility customers, companies with less ambitious clean energy goals (e.g., annual matching vs. hourly matching), or those with less experience buying clean energy.

Green Subscription Tariffs

The biggest difference between a green subscription tariff and REC-Only tariffs is that green subscription tariffs typically involve clean energy purchases rather than renewable energy credits.

There are several common types of subscription tariffs, including pass-through PPAs, bring-your-own (BYO) supply, and customized green tariffs.

Pass-Through PPA

With a pass-through vPPA, a utility will solicit subscriptions from corporate customers: once it gets enough clean energy subscribers, it will go procure a new clean energy resource. The utility will forecast the net spend of the PPA and get approval from its regulators for the charges that will be allocated to subscribers.

Because utilities typically set the price for this type of tariff based on forecast PPA wholesale market prices, they will employ a balancing mechanism for the customers. For instance, if the PPA price is $40/MWh, and the projected market revenue is $30/MWh, the subscribers will pay the residual $10/MWh. If, at the end of the rate period, the utility finds that the actual PPA market revenue was $32/MWh (meaning the utility charged subscribers $10/MWh for something that only cost $8/MWh), it will roll the difference of $2 into the following rate period as a credit for the subscribers. Conversely, if the actual PPA market revenue was less than expected, the subscribers would pay more the following year to make up the difference. This is an important feature because public utility commissions usually require utilities to demonstrate that customers who did not subscribe to the green tariff programs won’t be subsidizing the customers who did. That is, if the program ends up costing more, the utility must recover the difference from its corporate subscription customers rather than passing on the costs to its broader ratepayer base.

The nuances of this pass-through PPA tariff lie in the length of the commitment a utility will require from its corporate customers. Before procuring clean power, utilities need to be confident there will be adequate demand: If the program has a short-term commitment (e.g., a year), the utility will need to assess whether there is sufficient customer demand beyond that first year. That is why many subscription tariff programs typically procure fewer MWh than actual customer demand. An oversubscribed tariff means that if a customer discontinues participation, another customer is ready to step in.

However, oversubscription can create challenges for corporate buyers. Limited supply means customers often end up on a waitlist or only get a fraction of the amount of clean energy they wanted.

Subscription tariffs, including pass-through PPAs, usually follow one of two paths: customers can join on a first-come, first-served basis, or they can get a pro rata allocation. Unfortunately, neither option is appealing to a company committed to reducing its scope 2 emissions. It can be difficult to forecast emissions reductions or implement a decarbonization roadmap if you don’t know whether you’ll be able to access your utility’s program. For instance, Entergy is implementing a green subscription tariff in Louisiana (Geaux Green) but has a waitlist for large corporate customers (small businesses aren’t even eligible at this point). That waitlist has created uncertainty for companies in the state who don’t know whether they will be able to receive all the clean energy they want.

Pass-through PPAs are often attractive to smaller corporate energy buyers or those with less experience buying clean energy because the contract term is usually short, there is no upfront cost, and the payment mechanism – typically a subscription fee – is straightforward (although PPAs do require more expertise to contract than RECs).

Bring-Your-Own Supply

The next variation of green subscription tariffs is BYO supply. This is most common with retail providers, like those in ERCOT. The name says it all: corporate customers work with their retailer to integrate their own PPAs (e.g., solar, wind, storage, etc.).

Georgia Power provides a good example: It recently reached an agreement with the Public Service Commission and the Clean Energy Buyers’ Association to allow corporate customers in its territory to “work with third-party developers to identify and bring clean energy projects to Georgia Power’s system”. The utility must approve the company’s planned assets to ensure reliability, and benefits from spreading the cost of its transmission infrastructure to more load. BYO tariffs are appealing to large energy users with expertise in procuring, developing, and managing clean energy assets because it affords them greater control over their own energy mix. Experienced clean energy buyers and managers know how to contract this type of complex agreement. And BYO tariffs support more granular emissions calculations and clean energy goals, such as hourly matching and additionality, which is important to organizations with ambitious decarbonization goals.

Customized Green Tariffs

The third type of green subscription tariff is customized tariffs, which involve a negotiation between a retail provider and large corporate energy buyers. These tariffs – typically bilateral, but increasingly involving multiple utility customers – are essentially a supply agreement between the customer and the utility stipulating what clean energy resources each will provide. They also tend to involve longer-term commitments than other tariffs. For instance, when Silicon Valley Clean Energy developed a customized green tariff for Google a couple years ago to cover some of its office space in Northern California, the agreement had a ten-year term.

Because they are highly customized, these tariffs require significant power demands and expertise from the corporate buyer. Historically, that meant they were only available to the very largest energy users (and most sophisticated clean energy buyers) such as Google.

Utilities and corporate customers are trying to change that by designing the tariffs to be repeatable and scalable. For instance, Duke Energy recently proposed a suite of new tariffs to enable large corporate customers to “fund novel technologies like long-duration storage and advanced nuclear as they try to decarbonize.” And Google just announced a partnership with NV Energy in Nevada to develop a new “clean transition tariff” (CTT). The CTT establishes a long-term energy agreement between a utility and customer that can “facilitate investments into new projects that deliver clean firm capacity to the grid.” Nevertheless, for the moment, the scale, duration, and complexity of these customized tariffs will make them most appealing to large energy users and those with more experience in corporate clean energy procurement and/or ambitious decarbonization goals.

Green Tariff Considerations

There are several elements corporate clean energy procurement professionals should keep in mind when considering green tariffs:

• First, are you looking for additionality? Some tariffs, such as REC programs, may involve existing clean energy projects that do not qualify as “additional.”
• Second, what is the term of the commitment? For companies anticipating changes in their energy use, a long-term agreement may not be the right move. Others that want to hedge their energy costs over the next decade or more will want to avoid shorter-term agreements.
• Third, what is your exposure to the market? Does the tariff involve a fixed dollar per megawatt hour (MWh) like a REC-only purchase, or are you exposed to the performance of the underlying asset, as in a market-based green subscription tariff?
• Fourth, are you able to designate a specific resource ahead of making a commitment with your utility? Specifying the project allows companies to announce their support of a particular project that is greening the local grid.

In 2020, one-third of the U.S. was served by vertically integrated, regulated utilities, where standard PPAs or vPPAs (i.e., corporate contracts directly with clean energy developers) are difficult or impossible. Utility green tariff programs offer customers in regulated and retail markets alternatives, allowing them to invest in and claim the benefits of renewable energy. Whether a company opts for a REC-only program or pursues a customized green subscription tariff, there are options to suit different corporate energy uses, expertise, and sustainability goals.

Simplify Your Corporate Clean Energy Procurement

At Verse, we specialize in helping businesses navigate the complexities of clean energy procurement, vPPAs, and green tariffs. If you’re interested in exploring how green tariffs can support your corporate sustainability strategy, we’re here to help.

Electric grids are enormously complex, but when it comes to how to measure GHG emissions, we can break things down into three key types of emissions calculations – grid average emissions, marginal emissions, and residual mix grid emissions – to help us understand the environmental impact of electricity use. In this article, we’ll explain those concepts, some pros and cons of each, and explore when an organization might want to use them to measure its emissions.

Grid Average Emissions

Grid average emissions is the most general option for how to measure GHG emissions that tells us the average amount of greenhouse gases released to produce a unit of electricity (MWh) across an entire electric grid.

For instance, let’s say there’s a (tiny) grid with 100 MWh of load consumption for an hour of operation. To keep it simple, we’ll say 50 MWh of the generation is from renewables (wind and solar) and 50 MWh of the generation is from natural gas generators.

To calculate the grid average emissions, our equation would look like this:

50 MWh renewables x 0 kg CO₂/MWh (carbon-free renewables have zero emissions intensity) = 0 kg CO₂

50 MWh natural gas x 450 kg CO₂/MWh (EPA’s average emissions intensity of natural gas) = 22,500 kg CO₂

Grid average emissions factor = total CO₂ emissions / total electricity generated

So

22,500 kg CO2 / 100 MWh = 225 kg CO₂/MWh

Based on this calculation, the grid average emissions intensity is 225 kg CO2/MWh.[1]

Grid average emissions consider all the different sources of electricity, from coal plants to wind turbines. The greater the amount of renewable energy generation on a grid, the lower the grid average emissions will be. (The EPA’s Emissions & Generation Resource Integrated Database (eGRID) provides comprehensive data on U.S. electric power generation attributes.)

There are benefits to using grid average emissions when planning a clean energy strategy, particularly for organizations beginning their clean energy journey:

• Grid average emissions data is easily calculated, readily available and regularly updated, so it’s easy to access.
• It also provides a standardized benchmark for comparison with other companies or industry averages.

However, there are also some significant drawbacks:

• Grid average emissions do not reflect the marginal impact of a company’s energy consumption. For instance, if a company uses more energy at peak times when the marginal unit has greater carbon intensity, its actual emissions impact will be higher than the grid average suggests.
• For this reason, average emissions understate the decarbonization impacts of flexible loads or storage resources (e.g., shifting electricity use to cleaner times of the day when consumption would have less impact).

Should I Use Grid Average Emissions Calculations?

Grid average emissions are the most convenient measurement, which is why they have been used as the basis for how to measure GHG emissions and voluntary standards like the Greenhouse Gas Protocol (GHGP) and Science-based Targets Initiative (SBTi) (although that may change when the GHGP finalizes updates to its scope 2 guidance in 2026). For companies just beginning their clean energy journey, using grid average emissions offers an accessible entry point for carbon accounting. It enables simple benchmarking of a company’s baseline emissions and can be helpful as companies plan their overall decarbonization roadmap.

Marginal Emissions

Marginal emissions measure the impact of adding one more unit of electricity consumption to the grid. Typically, this additional demand is met by the power plants that can ramp up production, which is often a fossil fuel-powered resource.

For companies looking to maximize their carbon reduction efforts, a marginal emissions approach offers meaningful benefits:

• Marginal emissions calculations provide a more accurate reflection of the environmental impact of each additional MWh of electricity consumed, especially for decisions on when to use energy-intensive processes. (This 2023 paper, from Tabors, Caramanis, Rudkevich, provides an in-depth explanation of why companies should use the marginal emissions metric for greater transparency in carbon accounting.)
• Marginal emissions also provide a more accurate signal for the impact of modifying operations in real-time.

The drawbacks mostly revolve around complexity and potential difficulty executing this approach:

• Determining marginal emissions is complex and requires detailed data on grid operations and the mix of generating resources that vary in real-time. Accessing real-time or near-real-time data on marginal emissions can be difficult, as it may not be readily available or transparent from all grid operators.
• Marginal emissions are more volatile than grid average emissions from day to day and hour to hour, especially with increasing levels of renewables, making it challenging to establish a clear and consistent carbon footprint over time for planning purposes.

Should I Use Marginal Emissions Calculations?

By digging deeper into more dynamic data, companies can maximize their environmental impact and align operations with precise grid cleanliness. Marginal emissions data can provide greater insight into a company’s real-time impact, particularly if it’s using advanced, dispatchable technology (e.g., flexible loads and/or energy storage). But marginal emissions measurement requires sophisticated data analysis and is more challenging to implement than using average emissions data. When it comes to how to measure GHG emissions, marginal emissions calculations are a tool that requires a solid foundation of data and strategic capability to be used effectively.

While valuable for measuring real-time impact, marginal emissions may not be the appropriate measure for planning purposes. For many grids, particularly those with lower levels of renewable penetration, the long-term marginal unit is a natural gas generator. A forecast of marginal emissions factors will show little differentiation between wind and solar, which may disincentivize building a balanced resource portfolio and potentially lead to over-indexing on one technology.

Residual Mix Grid Emissions

Residual mix grid emissions refer to the emissions of a grid if you remove any specifically claimed voluntary clean energy procurement. The point of this calculation is to avoid double counting someone else’s voluntary procurement of clean energy.

Let’s continue our example of a grid with 100 MWh of load consumption, with 50 MWh from renewables and 50 MWh from natural gas generators. However, now we’ll assume that 25 MWh of the 50 MWh of renewables came from voluntary corporate procurement.

The residual mix calculation omits the 25 MWh of corporate procurement from the grid’s total generation. That leaves us with only 25 MWh of renewables for our grid emissions calculation:

25 MWh renewables x 0 kg CO₂/MWh

50 MWh natural gas x 450 kg CO₂/MWh = 22,500 kg CO₂

Total CO₂ emissions / total electricity generated (without the 25 MWh of voluntary procurement)

So

22,500 kg CO₂ / 75 MWh = 300 kg CO₂/MWh

Based on this calculation, the residual mix grid emissions intensity is 300 kg CO2/MWh.

As we can see, removing other companies’ voluntary procurement from our calculation raises the number of residual emissions for other companies. (In late 2023, the Center for Resource Solutions published this methodology for calculating residual mix emissions rates.)

As with the other accounting methods, there are benefits and drawbacks to using residual grid emissions. Benefits include:

• Residual grid mix emissions more accurately reflect the carbon intensity of purchased electricity (particularly in markets where renewable energy is actively traded).
• Using this calculation prevents double counting of environmental claims.

Some drawbacks include:

• Residual grid mix emissions calculations require accurate data collection, including detailed knowledge of the grid’s overall energy mix and specific renewable energy procurements made by other organizations.
• They are difficult to forecast because they depend on assumptions of voluntary procurement of environmental attribute credits from existing and new clean resources.

Should I Use Residual Mix Emissions Calculations?

The residual grid emissions metric provides the most transparent accounting of a grid’s emissions intensity because it strips out other companies’ clean energy activities, thus avoiding the double counting of renewables that’s embedded in grid average emissions. In essence, it prevents companies from claiming the environmental benefits from other organizations’ voluntary investments in clean energy. However, this measurement also requires the most data, not only from the grid operator and your company, but from other companies on their clean energy investments. The EU currently has more robust data on this than the U.S.

It’s worth noting that if the U.S. moves toward a residual emissions accounting system (e.g., in the upcoming GHG Protocol scope 2 updates), we can expect to see companies’ carbon emissions calculations increase because they will no longer be double counting other companies’ carbon-free energy investments. However, residual grid mix is a difficult metric to use for planning purposes as the measure is dependent on voluntary procurement activities.

Understand the Differences When Deciding How to Measure GHG Emissions

In a nutshell, the grid average emissions metric is the most used metric today, is the easiest to calculate, and gives us a high-level picture of a company’s emissions. The marginal emissions metric requires more sophisticated methodologies but provides greater insight into the real-time impact of a company modifying its electricity use. And the residual emissions metric requires additional data on voluntary procurement but provides a more accurate measure of a company’s carbon footprint when consuming energy from the grid. Understanding these distinctions can help organizations plan more effectively to reduce their environmental impact and get ahead of potential future voluntary and regulatory changes.

[1] This and other calculations in this article are simplified examples meant to provide a basic understanding of how mixed energy sources impact average and residual grid emissions. They do not consider real-world variables such as varying load factors, operational hours, etc.

What does it mean for a company to have an internal cost of carbon? 

A company’s internal cost of carbon is the price the company assigns to its greenhouse gas (GHG) emissions. The cost is typically not mandated by any external regulation but is a voluntary move by the company to guide its operational, financial, and strategic decisions to reduce its carbon emissions. 

Businesses can use their internal cost of carbon as a tool to quantify the economic impact of their carbon emissions, which integrates the consideration of climate change into business practices. A 2021 report by CDP showed increasing corporate adoption of internal carbon pricing (adoption grew by 80% in just over five years), including by many of the world’s largest companies. One of the report’s findings was “a correlation between the companies putting a price on carbon and those taking other strategic actions to integrate climate change issues into their business strategy as a means to reduce risk.” In other words, the report found that “internal carbon pricing goes hand in hand with emissions reduction activities.”

Why would a company set a cost of carbon? 

There are several reasons a company that is serious about achieving net zero goals or decarbonizing its processes would assign a cost to its carbon emissions. 

First, an internal cost of carbon encourages lower-carbon investments. It allows companies to evaluate investment decisions through a lens that favors low-carbon technologies and practices, reflecting the true environmental costs of their operations. 

• It can influence the pricing of products or services by accounting for the GHG emissions associated with their lifecycle.
• It encourages financial and operational decisions (e.g., where to site a new facility, or whether to invest in more sustainable designs or technologies) to favor options with lower emissions.

For instance, let’s say Company A is deciding where to site its next manufacturing facility. Facility X costs less on a dollar per MWh basis but emits more carbon; Facility Y is more expensive but has lower emissions. Depending on how much value the company attributes to carbon intensity based on its internal cost of carbon, it might prioritize the facility with cleaner operations.

A 2021 McKinsey report on “The State of Internal Carbon Pricing” noted that “internal carbon pricing was a key factor… in a European energy company’s decision to close several power plants, as the internal charge on increased carbon emissions cut into the expected profitability of those plants.” The smaller the internal cost of carbon, the more likely the company will just follow the dollars. The higher the internal cost of carbon, the more likely it will make decisions based on the carbon emissions. For instance,Microsoft did a blog post and webinar in 2022 about its internal cost of carbon and how that helped accelerate its decarbonization efforts.

Setting an internal cost of carbon also supports strategic planning and risk management by positioning a company for compliance with evolving carbon regulations (e.g., pricing mechanisms, taxes, or cap-and-trade systems). According to the aforementioned CDP report, more than 1,000 companies disclosed that “they are subject to carbon regulations, and an additional 717 companies expect such regulation within the next three years.” The authors conclude that “there is a direct correlation between [a company’s exposure to carbon pricing regulation systems] and the proportion of companies using or planning to use an internal carbon price.”

How does a company determine its cost of carbon emissions?

There is no one-size-fits-all method for setting an internal cost of carbon. (However, the 2021 McKinsey article and a 2017 article from the Environmental Defense Fund suggest carbon pricing thresholds, which are arbitrary and lack a defined global standard, are too low and do not account for the true cost of carbon emissions.) The process typically includes:

• Estimating the company’s current and future GHG emissions (both direct and indirect).
• Setting the right emissions reduction (and clean energy) goals for the organization.
• Considering the costs and benefits of various mitigation strategies. 
• Considering current and possible future regulations, market conditions, and the cost of carbon in voluntary and mandatory carbon markets. 
• Setting the price, typically based on external carbon pricing mechanisms, the cost of local carbon offset projects, or the estimated cost of in-house decarbonization.

What are some implementation challenges?

Assigning a price to a company’s carbon emissions can be tricky because it requires the right data (historical and forecasted), policy knowledge, and internal buy-in. A company must: 

• Accurately measure its emissions (both direct and indirect), which can be challenging for businesses with significant supply chains;
• Predict how those emissions will evolve (including both the company’s emissions and the emissions intensity of relevant electricity markets);
• Anticipate regulatory changes; and 
• Ensure internal and stakeholder buy-in.

Companies will also need to regularly review and adjust their internal carbon pricing to reflect changes in market conditions, regulatory landscapes, and their own operations. 

What’s the potential impact on decarbonization plans? 

The impact of setting an internal price on carbon depends on what a company is solving for. 

Let’s say a company is using the Valuation app in our Aria platform to solve for a 100% RE goal. In that case, the company wants to secure renewable energy credits at the lowest cost. A company with a 100% RE goal deciding between multiple clean energy projects would sort its options by each project’s implied REC cost (i.e., the net spend per MWh of renewable energy). The company wouldn’t consider the composition of the electric grid in terms of carbon intensity – it’s looking for a MWh of renewable energy in any grid and the most cost-effective way of purchasing it. Therefore, an internal cost of carbon, which does consider a grid’s emissions intensity, wouldn’t be meaningful for a company focused on 100% RE. 

Another metric a company can solve for in our Valuation app is GHG mitigation cost. This is effectively an implied carbon price. In solving for this goal, a company wants to know “What is my net spend per avoided or displaced emissions?” If the company is trying to prioritize potential decarbonization pathways and doing carbon accounting based on emissions rather than MWh of renewables, it will consider the emissions it’s avoiding relative to the net spend.

Solving for GHG mitigation cost typically shows that dirtier grids have more bang for the buck than cleaner grids. With this information, the company can prioritize investments and build a roadmap based on the decarbonization supply curve. For instance, many energy efficiency programs are to the left of the supply curve because they save money and reduce emissions; that is why most companies start their decarbonization journeys there. Clean energy procurement falls somewhere in the middle of the supply curve, with more advanced technologies (e.g., carbon capture and sequestration) to the right. 

Ultimately, the benefit of setting an internal cost of carbon depends on where a company is in its clean energy journey and what its goals are. It can be challenging to implement but can meaningfully aid a company in prioritizing its decarbonization roadmap and investments. 

Get prepared for GHG Protocol scope 2 updates. The timeline is dynamic, but that doesn’t mean companies should procrastinate planning for new guidelines.

Climate disclosures are increasingly expected for organizations everywhere. Whether driven by customers, employees, investors, or regulators, the trend is clear: More companies are disclosing their climate impact (by 2022, nearly 19,000 companies had shared their emissions through the Climate Disclosure Project).  

Increasing disclosure comes with additional scrutiny of the information presented. Some regulatory bodies, such as the U.S. Federal Trade Commission (FTC) have taken steps to limit “greenwashing,” the process of conveying a false impression of misleading information about how a company’s products are environmentally sound. To enable fair comparisons between companies, standardized reporting is necessary.

Although it may seem as though there are several different carbon accounting frameworks, the vast majority align with or are derived from the Greenhouse Gas Protocol (GHG Protocol).

Location-Based and Market-Based Methods of Carbon Accounting

In 2001, the GHG Protocol established a measure for scope 2, or indirect emissions associated with electricity consumption, using the location-based method. Under the location-based method, companies report emissions by multiplying regional emissions average factors by the amount of electricity consumed in that region and summing this calculation over all regions where they operate. Starting in 2015, the GHG Protocol added the market-based method, which allowed companies to use market instruments such as Renewable Energy Certificates (“RECs”) to reduce their emissions, effectively converting the emissions factor for energy consumed to zero for the volume of RECs purchased and retired. 

The implementation of the market-based method has led to significant voluntary action. Many companies have made commitments to 100% renewable energy (often referred to as 100% RE). Companies can meet 100% RE commitments by purchasing RECs or entering into a long-term power purchase agreement (PPA) with a renewable project developer. According to the Clean Energy Buyers Association (CEBA), energy customers have voluntarily procured more than 71 gigawatts of clean energy in the United State since 2014: In 2022 alone, these procurement deals were equivalent to 70% of all the carbon-free energy capacity added to the grid.

Nat Bullard, formerly at BNEF, noted in a recent presentation (slide 85) that 92% of the world’s GDP is covered by a net zero target, and large companies with sustainable goals seek to highlight their environmental leadership. In 2016, 92% of the Fortune 500 responded to the Climate Disclosure Project (CDP) using the GHG Protocol directly or indirectly, cementing its importance as a foundational standard. This means any scope 2 updates will have far-reaching impacts.

New Procurement Philosophies: Emissionality and 24/7 CFE

While the market-based method has driven voluntary action, there is growing sentiment that not all production of clean energy is equivalent. More specifically, most experts recommend greater consideration of where and when clean energy is produced. For example, adding solar to a grid that has ample solar production in the middle of the day has a much lower environmental impact than adding solar to a grid that relies heavily on coal and natural gas.  

There are two prominent schools of thought on what companies should aim to do with their clean energy procurement. One goal, advocated by Google, is to match all energy consumption with clean energy in the same grid and in the same hour, also known as hourly matching or 24/7 carbon-free energy (CFE). Another goal, championed by the Emissions First Partnership, is to focus directly on emissions impact and to procure clean energy wherever the most cost-effective carbon abatement can be achieved. This goal is sometimes referred to as emissionality. Both goals seek to decarbonize electric grids, albeit through different measures.

GHG Protocol Scope 2 Updates — More Granular Emissions Accounting 

As governments and other agencies debate expectations and rules for corporate clean energy goals, most have thus far supported the hourly matching approach. Executive Order 14057 established 24/7 carbon-free targets for U.S. government energy consumption. For green hydrogen, the EU has established hourly matching requirements, and it is likely that the U.S. will follow suit with the Inflation Reduction Act’s 45V tax credit.

The GHG Protocol, recognizing that more granularity is required in emissions accounting, is currently revising its guidelines, with new standards expected to be established in 2025. It is already clear that the impact of the changes will be significant: CA SB 253, which is estimated to impact 75% of the Fortune 1000, will require reporting of scope 1, 2 and 3 in accordance with the GHG Protocol. Further, the SEC will likely point to the scope 2 updates (and scope 1 and 3) in its disclosure requirements for all public companies.  

As for what the changes will be, various companies and experts are advocating for the 24×7 CFE and emissionality approaches. In addition, a third method based on marginal emissions impact has been proposed. While we don’t know how the debates will settle, one thing is clear — the rules will change, and companies need to be ready. More granular reporting, both with respect to location and time, presents an extremely complex math problem. Tools like Verse’s Aria software, which draws on generative AI to perform fast, rigorous analysis, can solve this problem in a fraction of the time it would take using spreadsheets.

Contact us to learn how Aria can help you more accurately forecast your organization’s emissions and optimize your clean energy procurement.