Last February, we examined scope 1, 2, and 3 emissions of the Greenhouse Gas (GHG) Protocol:
Scope 1 emissions – direct emissions from sources owned or controlled by a company
Scope 2 emissions – indirect emissions from purchased electricity, steam, heat, and cooling
Scope 3 emissions – all other emissions associated with a company’s activities
Here, we’ll address how a growing number of organizations tackle scope 2 electricity-related emissions to decarbonize their energy consumption.
And when you think of decarbonizing electricity (i.e., creating clean energy), you probably first envision solar panels installed on a warehouse roof. While some customers deploy on-site renewables for sustainability reasons and environmental benefits and tax incentives, in many cases, on-site resources are not available or do not generate enough energy to help larger customers truly affect their exposure to carbon emissions.
In these cases, they often seek to mitigate their exposure by supporting large, utility-scale renewables projects through one of four types of energy market-based instruments. We’ll describe each approach and some of the advantages, limitations, and risks inherent in each of these approaches:
1. Renewable Energy Credit Purchases (RECs)
2. Purchase Power Agreements (PPAs)
3. Virtual Purchase Power Agreements (VPPAs)
4. Utility Green Tariffs
Weighing the options to decarbonize your electric supply
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Renewable Energy Certificates (RECs)
We’ll start with Renewable Energy Credits because the concept of a REC is fundamental to all of the carbon management strategies discussed. The Environmental Protection Agency defines a REC as “a market-based instrument that represents the property rights to the environmental, social, and other non-power attributes of renewable electricity generation.” In other words, it’s the “green-ness” associated with renewable electricity generation. Each REC is issued when one megawatt-hour (MWh) of renewable electricity is generated and delivered to the grid. RECs possess several attributes, including a tracking ID, type of renewable, location and name of project, vintage of project, and the date of origination (when the actual MWh was generated).
The key thing to understand here is that RECs that represent the carbon-free attribute of the electricity can be sold separately from the actual renewable energy generated. So, when a wind farm or solar array owner sells RECs to a third party, the energy delivered from that renewable asset to the grid is no longer green—it’s now generic electricity.
The party purchasing RECs then can sell them to another entity or retire them. By retiring RECs, the buyer can claim that it has accounted for and decarbonized one MWh of its electricity consumption.
RECs can be either unbundled or bundled. Unbundled RECs are not tied to any specific project. Purchase of unbundled RECs—typically bought in monthly or annual contract allotments—allows the buyer to mitigate associated carbon emissions.
Unbundled RECs have some advantages. Because they are not tied to the location of a specific generation facility and can literally come from anywhere there’s a renewable generating facility, they create more flexibility for the buyer. They also increase revenue to the renewables developer and thus help to drive more renewable energy projects.
But adding unbundled RECS also comes at an additional premium over the cost of electricity. Furthermore, since one is simply buying an attribute rather than renewable energy from a specific project, they have no “hedging value.” In other words, if market costs increase, they don’t help you mitigate that risk, the same way you could if you were contracting to buy actual energy from a green power project.
Finally, they don’t stimulate new project development that might not have otherwise occurred—a critical concept known as “additionality.” Since they don’t drive new projects, they have fallen into disfavor among some of the leading voices in the net-zero/carbon neutral community as simply being insufficient in the effort to decarbonize our energy economy.
By contrast, bundled RECs are tied to the generation from a specific project and are generally not priced separately. In most cases, they are purchased as part of an upfront contractual commitment—for as long as 10–20 years—that helps developers obtain financing to get the project built.
Power Purchase Agreements (PPAs) and RECs
Let’s take a theoretical example to explain the concepts. Say wind farm developers in Texas want to build a new wind farm. They line up a corporate buyer with solid credit willing to buy the project’s output, including the bundled RECs tied to the asset. The buyer signs a 15-year PPA for energy at a specific price that includes the associated RECs, with enough energy to exactly match anticipated energy consumption over the life of the contract demand (remember, this is theoretical).
The developers then go to the bank with the contract in hand, which allows them to line up financing, and build the project. The buyer receives the energy—and retires the associated RECs—over the 15-year contract period, allowing a claim of climate neutrality. After the contract expires, renewable energy is still generated, so the developer/owner sells the output into the market and carves off and sells the RECs into the market as generic unbundled RECs no longer affiliated with a PPA.
PPA volumes have grown significantly in recent years, and they matter in the big picture. In 2001, PPAs accounted for 10% of all new renewables projects globally, totaling over 31,000 MW (U.S. buyers accounted for two-thirds of that volume). There are two basic types of PPAs: the Physical PPA, which involves actual delivery to the buyer, and the Virtual PPA (often referred to as a VPPA), involving a financial contract for a different arrangement. In both cases, these involve financing and construction of relatively large projects—often 100 MW or more—so smaller companies have typically been unable to participate unless larger sponsors allow them to join in the purchase.
To further extend the above example, a physical agreement would require that if the project is located in Texas, the buyer must also be located within the same power pool. In addition to a wholesale market in which generators (not utilities) buy and sell electricity, there also must be a competitive retail electricity market in which customers can purchase electricity from a third-party supplier.
The generator delivers energy into the Texas grid. The Texas-based buyer takes title to that energy, thus creating at least a partial hedge against price risk (the buyer is insulated against price increases since they have a contract for a fixed volume at a fixed price). The key challenge here is matching the actual hours of generation with the actual hours of customer demand. For example, a solar farm production profile involves generating a great deal of energy mid-day, stopping late in the afternoon. The customer consumption profile might look quite different. If prices are high in the early evening, a physical solar PPA doesn’t fully mitigate price risk.
Owing to the complexity of these arrangements, buyers must contract with a third party—typically a retail power supplier—to manage their energy services. There is also the critical issue of where the renewable asset is located relative to the location of the buyer since price differentials can be significant if there are transmission constraints in getting energy from point A to B. As an example of just how critical the location can be, consider that in the first week of May this year, prices per MWh in one area of Texas were several thousand dollars higher than they were just a thirty-minute drive away. That’s because lower-priced energy could not pass a congested transmission constraint (the line or transformer cannot handle the volume of power). So higher-priced electricity on the other side of that transmission limitation must be purchased by those unfortunate enough to be located there.
There is another key risk here, which relates to the non-performance of generating assets during periods when energy prices are high. Let’s take the example of the 2021 February Texas freeze to illustrate what can go wrong. In this case, buyers assumed that the turbines would run as they usually do when the wind blows. However, because of an unusual weather event, many turbines froze just as the cold snap started, failing to generate power. The buyers were then potentially exposed to the spot market, where prices pegged out at $9,000 for the better part of three days. Some retail electricity providers are now offering physical PPAs that are integrated into their monthly electric commodity bills so that the management of both complexity and risk is fully outsourced to the retailer.
In contrast with the physical PPA, a virtual PPA can involve a project located anywhere there is a competitive wholesale electricity market. Such projects are often resorted to when the buyer has multiple locations. A retail chain store with outlets in 25 states may opt for a VPPA. VPPAs may also be used when buyers seek economical projects located in a certain area. Texas, for example, is littered with wind and solar panel installations supported by VPPAs because the projects can deliver for half the price of other states where wind and sunshine are less abundant.
These contracts cover the lion’s share of PPAs in the U.S. but are more complex. The buyer never takes ownership or receipt of any of the electricity generated but instead engages in a financial swap typically settled monthly.
These swaps work like this: Buyer and seller agree to a fixed price (including the RECs). The project owner then sells energy into the competitive market at whatever the price is for that hour. Let’s take an example. Assume the contract price is $30 for every MWh over 15 years. The price today between noon and 1:00pm is $37. So the owner must pay the buyer $7 ($37 minus $30) for every MWh generated during that hour. But what if the price falls to $20 the next hour? Now it’s the buyer who owes the seller, in this case $10 per MWh ($30 minus $20) for the period. The contract price stays fixed at $30 for the life of the contract, but every time the price is high or lower than $30, somebody owes the other party for the difference times the total MWh delivered in that hour. Such swap arrangements can require registration, record-keeping, and reporting per the Dodd-Frank Act.
The biggest risk here for the buyer is that the market may end up being extremely soft—especially if a large number of renewables projects are built in a market after a contract has been signed. That’s because the more wind and solar energy projects that are developed, the more prices during the hours of output tend to fall—a phenomenon known as “negative co-variance.”
The example from California (below) shows just how this works. Note two outcomes: First, market prices are lowest during the hours of maximum solar power output. Second, as the projected amount of solar power saturation increases from 2021 to 2025, prices are projected to fall further. That increases the likelihood that the buyer will be writing larger checks over time.
Utility Green Tariffs
In areas where there are no competitive markets—where independent generators compete and sell electricity into the market—many vertically integrated utilities—that still own both the generation and wires and poles—are responding to customer demands with “green tariffs.” The latest consolidated numbers from the end of 2020 indicate that 19 green tariff programs had been developed, supported by 4,729 megawatts (MW) of new renewable projects.
Green tariffs involve the development of renewables projects specifically tied to that customer rate. So, for example, Michigan utility Consumers Energy developed a green tariff that tied energy consumption at data center company Switch and auto manufacturer GM to a wind farm located within the state, and each purchaser paid a fixed price per MWh consumed.
With green tariffs, the electric utility is often the initial developer or purchaser, which helps expedite project financing. Unlike PPAs, which generally involve one or two larger buyers that support project financing, many green tariffs can offer smaller companies a chance to participate. This approach is also less risky to the buyer since it often, but not always, involves shorter contract lengths.
The opportunities to decarbonize Scope 2 electricity consumption have increased in recent years, but those opportunities are often complicated and involve various levels of risk. There’s still quite a way to go to make many of these options simpler, less risky, and more accessible, especially for smaller companies. As the markets continue to evolve, there’s hope that the landscape will change.