Author: Amy Chiang

Amy Chiang is a Manager on the Energy and Climate Practice team where she works with corporations on strategy and implementation of renewable energy and climate solutions, with a focus on VPPA procurement.

U.S. renewable energy market: Pricing trends and projections for PPAs

2022 was an unprecedented year for global energy markets, with levels of volatility and uncertainty that the world had never experienced. In the past year alone, the market experienced cascading impacts from supply chain constraints, resource shortages due to the Russia-Ukraine war, as well as tariff and regulatory uncertainty. Any one of these factors would test energy markets and make renewable energy procurement challenging; but the convergence of all three resulted in a year full of surprises for those looking to procure renewables in the U.S. and globally. As we reflect on 2022 and look ahead into 2023 and beyond, we offer a few insights related specifically to the power purchase agreement (PPA) market for corporate energy buyers. 

U.S. Renewable Energy Market – 2022 in review

On one hand, 2022 was a banner year for operational PPA projects, as many local and global factors, such as those mentioned above, drove an increase in energy prices that resulted in large positive PPA settlements for offtakers. On the international stage, energy supply challenges caused by the Russia-Ukraine war drove up the demand for U.S. exports. Locally, increasingly hot summers and cold winters contributed to higher energy demand. These compounding factors led to the highest energy prices in recent history across nearly all U.S. wholesale electricity markets. 

Most prior projections for 2022 already anticipated higher electricity prices due to increasing demand and lagging supply, however, the actual prices (and thus PPA revenues) in 2022 far exceeded those forecasts. For those buyers with an actively operating project, this lucrative year can serve as a buffer for future uncertainty around the later years of the PPA contract, and can enable them to invest its unanticipated earnings in other renewable energy and emissions reduction initiatives as part of a larger climate goal.

U.S. Renewable Energy Market – 2023 and beyond

Looking ahead, while energy prices are projected to stay elevated over the next 2-3 years, this mainly benefits companies whose PPA projects are already operating or will come online during this near-term period. For organizations seeking to enter the PPA market now, the landscape looks a bit different – PPA prices have risen drastically, supply of projects is low, and contract terms are less buyer-friendly than in the past. Additionally, its questionable whether or not projects that are currently in the contracting process will begin operations within this 2-3 year window in which electricity prices are forecasted to remain high.  

The speed at which the PPA market shifted from being relatively buyer-friendly to being distinctly seller-friendly was a surprise for many in 2022. Given the continued high demand for projects from corporate buyers, it’s unlikely that these current market conditions will change anytime soon. 

Power Purchase Agreements largely came about as a mechanism for companies to procure renewable energy when there are limited local options that result in new renewables being added to the grid. For organizations that signed deals during the period of low PPA prices, these contracts have likely generated revenue, as an added, if unexpected, benefit. However, with those days behind us, the conversation should now refocus on how these projects can help companies meet their climate goals in a way that is more impactful, and possibly financially on par with, purchasing unbundled renewable energy certificates (RECs). 

In the longer-term (beyond 2-3 years), projections show that current high electricity prices will likely stabilize and eventually decline, as increasingly large quantities of low-cost renewables penetrate the electricity grid. This further validates the expectation that PPA contracts signed today are likely to be lower in projected value compared to contracts of the past. PPAs executed in 2023 or beyond will most likely result in a net cost to the buyer over the project term – and in most markets, this cost will likely be higher than the equivalent cost of purchasing unbundled RECs (see graphic below). In the recent past, ERCOT has been the most popular market for PPAs due to having the most attractive economics and relatively streamlined permitting and interconnection processes. However, other markets such as MISO and CAISO may start to regain traction as corporations look to diversify their portfolios away from the ERCOT market.

U.S. renewable energy markets prices

Figure 1: Projected Implied REC value ($/MWh) comparing forward purchases of unbundled RECs in 2025 compared to solar and wind PPAs across 5-6 ISO markets.

In this ever-evolving market, both future electricity prices and supply & demand for projects will ultimately determine and drive the value of PPAs going forward. While the Inflation Reduction Act (IRA) is expected to spur development of projects and therefore increase supply, increased demand from corporate buyers may continue to keep PPA prices high (thereby keeping expected financial values muted). Although we are hoping to see some increased stability in the PPA market this year, it is clear that PPA prices would not go back to pre-2022 levels. Overall, the only certainty is that the future is unpredictable, and, like trying to time the stock market, it is impossible to guess the “best time” to go to market for a PPA. 

While PPAs are not the best-fit option for all organizations, they remain popular since they continue to offer a impactful (i.e. new, local) renewables solution to address large, distributed electricity load. We’re already seeing some buyers pursue PPAs not only for the financial benefits, but also as an important tool to address their scope 2 emissions and meet their increasingly ambitious climate targets. We expect to see this trend increase in the coming years.

If you have questions about whether a PPA is right for your organization or are interested in PPA monitoring services, please feel free to reach out. We’re happy to help. Get in touch today

Maximizing carbon displacement with power purchase agreements: Part 1: Choosing your market

When organizations embark on a new renewable energy procurement, specifically a power purchase agreement (PPA), they often have several criteria that they are trying to satisfy with the new project. With the climate crisis becoming critically urgent, many of 3Degrees’ clients are prioritizing carbon displacement value as one of these decision making criteria. Put simply, more buyers are interested in ensuring that their renewable energy project has the largest climate benefit possible – which is good news! 

In this three-part blog series, Maximizing Carbon Displacement with PPAs, we will dig into strategies that organizations can use to evaluate PPAs for decarbonization impact. To kick off the series, we start with one strategy that is fairly straightforward: choosing your market. 

Carbon intensity in the U.S. grid

Some buyers have a very specific market in mind for their procurement, such as one that maximizes potential hedge value, projected financial value, etc.  However, they may not be aware of how that market compares in supporting their desire to maximize the project’s carbon displacement value – meaning the amount of carbon emissions that are actually being “pushed off” the electric grid by the renewable energy from the new project. 

Most people are aware that some regions of the country – and the world – rely more heavily on polluting energy sources to power their electric grid so, naturally, a project located in one of these higher carbon intensity regions will have a larger carbon displacement benefit than one located in an area that already has a lot of renewable energy generation capacity. In the U.S., this example can be brought to life if you look at the Great Plains states that are relatively coal dependent, which results in a higher carbon intensity compared to Texas, for example, the national leader in wind energy production (19.5% energy generation from wind in 2020). So, a project located in North Dakota would have a significantly higher carbon displacement value than a project in Texas, which means our clients may decide to execute renewable energy PPAs for projects in North Dakota instead of Texas. 

One important note as it relates to a renewable energy project’s geographic location and the example above: the Greenhouse Gas (GHG) Protocol, used widely for carbon accounting, does not distinguish between a project located in a higher carbon intensity market and a lower one for the purposes of carbon reporting; a renewable megawatt hour (MWh) is a MWh, regardless of its location. So in a company’s GHG inventory, a project in North Dakota is not going to look any different than a project in Texas. Customers can certainly feel better knowing their project has a more significant impact if it’s located in a higher carbon intensity region, but it’s not going to show up any differently in their carbon accounting.

Carbon intensity, and why time of day matters 

Clients are often curious how carbon intensity in a grid is calculated. There are different methodologies used to calculate a market’s carbon intensity that all relate to how the emissions factors in a grid are calculated. Two of the most common factors are average emissions and marginal emissions

Data from U.S. Environmental Protection Agency. Average emissions rates in the U.S. based on grid regions. The northwest and northeast are dominated by hydro, while nuclear leads in the southeast, coal is the primary in the rust belt and mountain west, while the south is led by natural gas.


The average emissions method looks at all power plants operating in a given market and the associated emissions generated during a certain time in that region, and divides them by the amount of electricity produced during that same time period. 

To calculate carbon intensity using the marginal emissions method, you only need the emission factor of the marginal power plant in the generation stack for a given market – the rest of the power plants operating do not factor into this calculation. 

The marginal emissions calculation is intended to take into consideration which resource was last added into the generation mix and, therefore, would be the marginal plant displaced if additional renewable energy assets were added to that grid. Both methods can illustrate why time of day matters for carbon intensity, but the marginal power plant calculation is more influenced by this component and, therefore, renewable energy technology as well as regional power plant operation trends. For example, wind generation peaks at night, a time of low energy usage, which means most generation is coming from base load plants. Therefore, a wind PPA executed in a state with strong nuclear base load energy will have a lower carbon displacement value than a wind PPA in a state with more base load coal generation. This is because the wind power would be displacing the low emissions coming from nuclear plants vs. higher emission coal plants.  However, a solar PPA in this same state may have a high carbon displacement value because the facility would be generating electricity during hours that natural gas peaking plants are online to meet peak demand. 

To recap: when deciding where to procure a renewable energy PPA, it’s worth closely considering the market – and how specific renewable technologies will intersect with that market – in order to ensure maximum “carbon displacement bang for the buck.” 

Up next: Carbon arbitrage

In the next blog in this series, we’ll take a look at how alternative technologies can play a role in carbon arbitrage. In the meantime, if you have any questions about your company’s renewable energy procurement strategy and would like support with it, please reach out to us.

PPA Advisor Fees: Which Fee Structure is Right for your Company?


Having set ambitious climate goals, your company is now deciding how to go about achieving those targets. Many corporations are entering into power purchase agreements (PPA) to procure large volumes of renewable energy. These transactions are a convenient way to quickly achieve renewable energy goals, but can expose buyers to significant risk factors along the way. Companies that do not have in-house expertise in wholesale power markets and PPAs find it critically important to partner with an experienced advisor and to incentivize success with the appropriate compensation structure.

The scope of an advisor’s work can include stakeholder education and alignment, procurement management and financial analysis, and contract negotiations and performance monitoring. Perhaps more importantly, an advisor’s role requires mitigating the financial risks of wholesale electricity market exposure, as well as any development-related risks associated with counterparties, project financing, and other execution risks.

While there are multiple advisors who can perform these PPA services, cost and compensation structures can be opaque and vary widely making it difficult to select an advisor with aligned incentives. Understanding how the compensation structures work is fundamental to ensuring a fair and successful PPA transaction. Below we describe common fee structures in the market.

Success Fee

In the success fee pricing structure, the advisor’s fee is amortized over the life of the contract and rolled into the PPA payments as a “lift.” This means you pay for the advisory work over the project’s operational lifetime instead of allocating budget to the procurement process upfront. While the advisor is only paid if a contract is successfully executed, success fee structures may have a recapture fee if no transaction is executed once the engagement passes a certain milestone. Although success fees are typically the most expensive option on a total cost basis, the avoidance of an upfront cost is attractive to many buyers.

Success fees are ideal for companies that do not want to spend budget upfront on the PPA procurement process or deal with cost allocation across multiple departments.

There are two main ways that success fees are offered, which can be standalone or combined:


While advisor fees have not traditionally shared in buyers’ wholesale power market risk exposure, 3Degrees has worked with clients to create performance-based success fee structures to share that risk.

Time and Materials

A time and materials (T&M) pricing structure allows for the most flexibility as you pay for the work performed on the renewable energy transaction as it occurs. At the end of the engagement, there is no pressure for your organization to sign a contract. Furthermore, the fee will not vary based on the selected project’s final size, technology, or other specific attributes. This is typically the lowest cost option for our clients, but it requires budget to be allocated to the procurement process upfront, which may be a tough sell internally – especially in the current economic environment.

T&M consulting fees typically result in the lowest total advisor cost for buyers, but require upfront budget allocation which can be a hurdle for some organizations.

Fixed Fee

A fixed fee structure identifies a set dollar amount that is paid to the advisor either entirely upon contract execution or on a milestone basis. This structure is often offered at a premium to T&M pricing because the work is performed at risk by the advisor. Similar to T&M pricing, there is no pressure for your organization to sign a contract and the fee will not vary based on the selected project’s final size, technology, or other specific attributes.

A fixed fee could be a good option for companies that want a PPA transaction executed for a guaranteed price without cost overruns which can occur under the T&M structure.

SUCCESS FEE ($/MWh) High Over PPA term* No No Yes
SUCCESS FEE (% of revenue) High Over PPA term* No Yes Yes
TIME & MATERIALS Low Monthly up to PPA execution Yes No No
FIXED FEE Medium Milestones up to PPA execution Yes No No
*Success fee structures may have a recapture fee if no transaction is executed once the engagement passes a certain stage.

In our experience, there is not one single pricing structure that will work best for every company. Success fees are popular compensation structures that allow organizations to attain their climate goals while managing budget constraints in the COVID-19 economy. While we have seen increasing interest in success fees recently, 3Degrees continues to offer each of the pricing structures described above to best meet the needs and preferences of our clients.

Success fees are popular compensation structures that allow organizations to attain their climate goals while managing budget constraints in the COVID-19 economy.