A new white paper from REsurety, with contributions from Hannon Armstrong, a leading investor in climate solutions, offers an in-depth analysis into how using an “8760” energy model can lead to significant errors in revenue modeling — topping 30% in some high renewable penetration markets.
An “8760” (also known as a “typical meteorological year,” or “TMY”) is the expected typical generation for a given wind or solar project for each of the 8,760 hours in a non-leap year. Despite their widespread use in the renewable energy industry, using an 8760 to project financial performance can lead to significant errors in revenue modeling.
Fill out the form below to access the white paper.
DOWNLOAD THE REPORT
Pro Tip: This video looks better in HD! Click on the gear in the bottom right corner and change the quality to 1080p for best results.
Until recently, comprehensive granular data about which individual power plants were generating during the February deep freeze in Texas didn’t exist. As a result, most analysis to date has focused on aggregate fleet performance (such as our analysis of wind and solar performance given local weather conditions) or the meteorological conditions that caused the event. While limited project outage information was available from ERCOT, the hour-by-hour performance of each plant had not been made public – until now.
Hourly project-level generation data is released by the Texas grid operator on a 60-day lag, which means that February information was just released recently. Each month, our market intelligence tool REmap processes this data from the grid operator, making it easy to visualize and assess project-level performance with a couple of clicks.
In this analysis, we’ll take a closer look at the project-level hourly performance data and seek to identify key trends and takeaways from that granular dataset. We will focus on wind projects, as solar projects were widely known to have performed or overperformed relative to expectations.
This article analyzes the performance of wind projects in all of ERCOT. For individual project consultation and to understand what the February 2021 event means for your projects, either in development or already operating, speak to our REmap team today.
To start, we want to highlight the high performing wind projects in ERCOT’s fleet. We’ll look at this by the project’s net capacity factor, that is, how much energy the project contributed to the grid adjusted for the size of the project. Here, we are focusing on performance during the deep freeze, so from February 11 through February 19.
Figure 1. Top 10 performing ERCOT wind projects 2/11-2/19, by capacity factor.
Top Revenue Makers
While generating essential megawatt-hours was critical to supporting the grid during the winter storm, another important topic is the financial impact of the event.
It is hard to overstate the impact of the February 2021 winter storm on power markets. Power prices were at or near $9,000/MWh for nearly 100 hours, leading to a cumulative price that was over 10 times that of the prior “extreme” market event in August 2019.
Figure 2. Observed cumulative power prices at ERCOT North Hub in different months.
Overall, the financial “winners” were those projects that generated during the highest-price hours (the hours in which scarcity conditions elevated power prices). It is important to note, however, that the high value of generation during high priced events is often shared, in whole or in part, with the offtaker of the project as a result of contract-for-difference hedge settlements (in all its various flavors: vPPA, pgPPA, PRS, P99 Hedge).
Let’s look at the highest value projects across Texas at each major hub.
Figure 3. Top 5 performing wind projects in February 2021, by region, ranked by generation-weighted real-time price at the hub.
What’s common across Texas is that the around-the-clock (ATC) price of power in February 2021 exceeded $1,500/MWh. After that, what should stand out is that wind projects across South Hub were best-positioned to generate valuable energy and capture record-high prices. Projects at North Hub experienced a significant shape discount, while the best projects at West Hub experienced a more neutral shape relative to the around-the-clock (ATC) price.
The highest realized value was achieved by Peyton Creek Wind Farm, with a generation-weighted realized hub price that exceeded $2,000/MWh.
Congestion Impacts in ERCOT South
Not only did Peyton Creek Wind Farm benefit from valuable generation at the hub level, it also benefited from limited node-to-hub congestion (also known as “basis”). The project is located between Houston and Corpus Christi, with few wind projects nearby to compete for valuable transmission capacity. Many of the other highest-value ERCOT South wind projects are all located in a relatively congested area further south, and experienced materially worse grid congestion.
Figure 4. Node to hub basis (in $/MWh) in February 2021 across Texas wind projects.
Figure 4 shows that basis impacts varied widely across the ERCOT region during the winter storm. Positive basis (dark green) indicates that a project observed a higher LMP at the project node than the price at the hub. This is generally in the project’s favor, as offtake agreements usually settle at a hub. Any positive basis then is upside for the project, while negative basis implies a loss for the project.
Although most of ERCOT experienced relatively minimal node to hub basis during the winter storm, projects in the ERCOT South region saw significant basis impacts. When wind speeds are high and projects are generating, it’s not uncommon for projects in South Texas to suffer from congestion-related impacts.
To understand what was happening in ERCOT South it is helpful to dive one level deeper. Figure 5 shows the hourly price and generation data for a coastal Texas wind project, Cameron Wind, that saw significant negative basis during the event. The middle chart highlights the difference between the nodal and hub price at one specific hour on February 17th — almost -$4,700 — and the bottom chart shows the observed hourly generation.
Figure 5. From top to bottom: real-time hourly price (project node in red, ERCOT South hub in green), node-to-hub basis, and generation for Cameron Wind in South Texas for February 13-20, 2021.
While coastal Texas wind projects fared the best (see Figure 3), there was considerably more variability in their financial performance in February 2021 than during past events. Figure 6shows historical real-time shape in dollars per megawatt-hour from August 2019 to February 2021 for several wind projects along the coast of south Texas.
Figure 6. Historical shape (in $/MWh) from August 2019 to February 2021 for various coastal Texas wind projects.
Figure 6 shows these projects all performed similarly during the extreme price event in August 2019, but diverged materially in February 2021. Several coastal Texas wind projects saw extreme negative shape values in February 2021, a dramatic divergence from the August 2019 event. The negative shape values are likely due to poor operating performance during high-priced periods.
The worst revenue and shape values were seen by the wind and solar projects that were offline for the duration of the high priced event. These projects were unable to generate — whether due to operating decisions, transmission constraints, or other reasons — when electricity was most in demand and power prices at their highest. (Analysis of hourly data shows, for example, that Big Spring Wind Power generated zero megawatt-hours between February 10th and February 19th.) As such, their generation-weighted value is significantly lower than the around-the-clock price of power at the hub. These projects were heavily concentrated in West Texas.
Figure 7. Lowest performing wind projects in February 2021, by region, ranked by generation-weighted real-time price at the hub.
The deep freeze in Texas was an unprecedented event in ERCOT’s history. Granular analysis of projects in the region gives visibility into which projects benefitted from the period of extreme market conditions and which projects didn’t. Going forward, as the focus of generators and policy-makers alike shifts towards resilience, having visibility into this performance data will become more important than ever.
REmap is REsurety’s market analytics platform, an interactive tool that allows users to quickly and accurately understand the impacts of weather and power markets on the value of renewable energy projects. To learn more, visit resurety.com/remap or contact us at [email protected].
Purchasing renewable energy is a means to an end: decarbonization. Yet, renewable energy projects are not all equal when it comes to cutting carbon.
At REsurety, we’re developing a new carbon impact measurement tool called Locational Marginal Emissions (LMEs) that measure carbon emission reductions at the granular level: the electrical node where the carbon-free energy is injected into the grid.
What becomes clear when working at this level of granularity is that one clean energy project can have dramatically more carbon abatement impact than another – even when they are located just a few miles apart. For example, we assessed the Locational Marginal Emissions of two otherwise comparable solar projects in west Texas and found that one displaces twice the carbon emissions as the other.
Our team sees better measurement of carbon impact as an urgent need. Over 300 companies have joined the RE100 initiative, committing to 100% renewable energy. These companies have increasingly turned to virtual Power Purchase Agreements (vPPAs) to meet their sustainability targets. But when a corporation purchases off-site renewable energy through a vPPA to offset a portion or all of its energy usage, it typically measures its carbon impact in megawatt-hours (MWh) which – depending on the project – can dramatically over- or underestimate the true carbon impact of that project’s operations.
A shift is now underway from 100% renewable to carbon zero – which is quite a different goal. Renewable purchases are easy to measure, while measuring the carbon they eliminate has been challenged by a lack of data.
Nevertheless, two dozen tech firms and environmental groups appealed to the Biden Administration to adopt a 24/7 Carbon-Free energy approach like the one Google is employing to achieve “clean energy every hour, every day, everywhere.” In March, the Administration in its American Jobs Plan agreed to apply that standard to federal buildings.
More recently, on Earth Day 2021, President Biden doubled down on the U.S. carbon-cutting commitment, promising world leaders to put the U.S. on a path to cut its carbon emissions in half by 2030.
The ultimate goal is clear: to reduce our carbon emissions as quickly and cost-effectively as possible to avoid further impacts of climate change. Which projects get us there the fastest and at the lowest dollar per ton avoided to date has been far from clear. As Google – which initiated the 24/7 Carbon-Free initiative in 2017 – has highlighted,the necessary data to track progress accurately “is generally unavailable.” We believe that LMEs solve that problem.
Our new white paper, “Locational Marginal Emissions: The Force Multiplier for Amplifying the Carbon Impact of Clean Energy Programs,” co-authored by Dr. David Luke Oates of REsurety and Dr. Kathleen Spees of The Brattle Group, dives into exactly why some renewable energy projects mitigate more carbon than others, and may thus be a better investment decision for meeting sustainability goals. “LME-based accounting can form the basis of more cost-effective public policies and corporate sustainability strategies,” Spees says, “by guiding the development of clean energy projects that maximize the carbon abatement value of every program dollar spent.”
The name Locational Marginal Emissions comes from the power-price corollary: Locational Marginal Price – the cost to serve one MWh of incremental load at a given location. In other words: if you’re going to consume one incremental MWh at that location, what generator or set of generators is that energy going to come from, and how much does that “marginal” generator need to be paid to produce that incremental MWh?
The Locational Marginal Emissions metric uses the same fundamental concept, but it incorporates the marginal generator’s emissions rates. By calculating the LME, we can accurately measure the carbon impact, or the emissions reductions, of generating clean power at any given moment at any given location on the grid.
Referring back to our example of the two west Texas solar projects, when we analyzed the data for those otherwise comparable projects, we found that available transmission led to one project displacing coal in the peak of the day’s sunshine, while transmission constraints resulted in the other causing the curtailment of another nearby solar project.
Cumulative carbon emissions avoided by two wind projects and two solar projects in Texas show just how much carbon emissions avoided by renewable energy vary, even within a given sub-region on the ERCOT grid.
The Need is Pressing
Tackling climate change at a massive scale requires us to maximize the carbon impact of every dollar spent on clean energy. And not every megawatt or megawatt-hour is created equal. We need transparency around the actual carbon emissions avoided by a given renewable energy project in order to select and invest in renewable energy projects with the greatest carbon-reducing impact on a dollars-per-ton basis.
We are not alone – companies and their stakeholders are calling for more accountability around their sustainability targets and investments, ensuring that the scale of their impact matches the scale of their good intentions.
Right now we’re working on what these corporate ESG leaders have been asking for: clearer, more transparent answers on how many tons of carbon emissions are actually avoided by the renewable energy projects they’re buying energy from.
Data-driven insights made possible by Locational Marginal Emissions will allow companies to select and invest in renewable energy projects with the greatest carbon-reducing impact.
If companies are serious about reducing their Scope 2 emissions from energy use, they need better data — data that reflects the actual carbon-intensive units their clean energy megawatt-hours are displacing.
Purchasing renewable energy is a means to an end: decarbonization. Yet, renewable energy projects are not all equal when it comes to cutting carbon. We’re developing a new carbon impact measurement tool called Locational Marginal Emissions (LMEs) that measures carbon emission reductions at the granular level: the electrical node where energy is injected into the grid.
Fill out the form below to access our white paper on Locational Marginal Emissions.
Increasingly popular “24/7 clean energy” strategies can miss project details if they’re based on regional and annual averages, Power Finance & Risk reported May 10 in a story by Taryana Odayar.
“That strategy ignores the sub-regional transmission congestion that can have a significant impact on carbon intensity,” the magazine quoted REsurety CEO Lee Taylor saying on Norton Rose Fulbright’s May 4 Currents podcast . Instead, REsurety has a new way to measure carbon called “Locational Marginal Emissions” that looks at exactly where and when energy is added to the grid.
“We have a common enemy which is that not all megawatt-hours are equal, so a megawatt-hour generated from one location can be meaningfully different from another location based off of the electrical grid that that’s operating,” Taylor said on Currents. “As companies are trying to go carbon-neutral, carbon-free, carbon-negative, they need more than annual megawatt-hour accounting to do that effectively.”
Power Finance & Risk linked to REsurety’s white paper with The Brattle Group on LMEs, which compares two solar projects in West Texas. One displaces twice as much carbon because it has access to transmission to displace coal-fired generation, while the other curtails another nearby solar plant. The result helps companies such as Google that are committed to 24/7 strategies find out exactly how much carbon they’re reducing.
Hourly power price and generation data is now available in REmap, a tool widely used by leaders in the renewable energy industry to identify value, understand risk and optimize offtake and hedging strategies. REmap’s new Hourly Data Explorer allows users to investigate the hourly performance of thousands of operational and synthetic projects.
The Hourly Data Explorer continues REsurety’s commitment to provide unrivaled breadth of market intelligence and depth of project-specific insight, empowering key decision makers.
“The February winter storm across the Southwest provided an extreme example of an already clear trend: fortunes are made and lost by generating during the right hours, not simply by achieving a high annual energy production,” said Lee Taylor, founder and CEO of REsurety. REsurety launched the map-based tool in May 2020 as an SaaS product, to provide the data and analytics required by the complex, data-driven industry that is the modern renewable power market.
Last year, REsurety used REmap to reveal how low energy demand during the coronavirus shutdown — combined with low natural gas prices and high renewable generation in April 2020 — sent the production-weighted wholesale price of wind-generated electricity to all-time lows across the SPP, PJM and MISO power grids.
This week, in a column for Utility Dive, REsurety digs into what REmap data tells us are the top trends and takeaways in renewable energy markets today.
The resiliency that the Texas grid so badly needed in February 2021 was foreshadowed by similar — though smaller — power market events in 2020 and 2019. “One thing REmap shows us is what renewable energy projects could have generated during the Texas deep freeze of February 2021, based on the actual wind and solar resource available,” Taylor said.
Theoretical project generation data, given site-specific weather conditions and plant characteristics, will be available in REmap in early March. Hourly metered generation at the project level for ERCOT projects will follow in early May. REmap can help users understand the financial implications of the February 2021 deep freeze on contract settlements, and inform their expectations moving forward.
REmap stands for “Renewable Energy Market Analytics Platform.” To keep it populated with the latest information, REsurety collects, cleans, and analyzes billions of data points from a wide range of sources. Industry leaders use the resulting massive database to inform their decision making on new investments, to benchmark against their peers and competitors, and to inform their offtake strategies – both as buyers and sellers. Current REmap customers include developers, investors, C&I buyers, and advisors. Joan Hutchinson, Managing Director of Marathon Capital and an early REmap client, described REmap as “a sea change in the access to quantity and quality of data.”
The deep freeze in Texas seems almost certain to be the top energy story of 2021. The meltdown of the ERCOT power grid had dramatic implications at the individual project level, as the financial performance of each project was driven by the weather conditions at its particular location. For example: iced blades caused some wind projects to shut down near the beginning of the cold weather event, missing out — or causing their offtakers to miss out — on a potential windfall due to the record-breaking $9,000/MWh pricing that was sustained for days during the event. Meanwhile, some solar projects exceeded expectations during key high-priced hours.
We are excited to dig into the specifics of which projects performed and outperformed as the granular data becomes available. While detailed analysis of the Texas event crisis is still ongoing, we’ve analyzed the hourly generation and price data from every available renewable energy project in 2020 to help understand takeaways and trends in renewable energy markets from last year’s performance.
The shocking events of last month notwithstanding, we expect many of these trends to continue in 2021 and beyond, while other new trends are sure to emerge as well. Here, we share seven of our findings, and the data behind them.
1. Renewable energy project value continues to be highly variable.
The value of renewable energy project generation across the country in 2020 ranged from a low of less than $1/MWh to a high of $57/MWh. (Measured as the value of project generation, sold at the nodal/hub real-time Locational Marginal Price (LMP), where project generation is either observed or modeled depending on data availability.) A complete summary of renewable energy project values observed in 2020 across various markets is below:
Generally, we see that the highest-value projects are located in areas of low renewable penetration of the same technology — for example, wind in CAISO or solar in ERCOT. These projects can distinguish themselves by offering a production profile that is complementary to other renewable energy projects nearby and can capture high-value hours currently underserved. Said otherwise, projects that can generate when generation from other sources is low stand to benefit from higher market prices due to basic supply and demand.
Looking in more detail, we see a wide range of value across individual projects, driven both by project production profiles and local congestion on the grid.
Below we dive into the drivers behind some of the wide-ranging values in the table above.
2. Congestion continues to be a revenue-maker or breaker.
One data point that should jump out in the above table is that the highest-value project of any renewables project in the country is a wind project in ERCOT West! While most wind projects within ERCOT West produced power worth comparatively little (the average real-time generation-weighted nodal price in 2020 was ~$10/MWh), the Notrees Wind Farm achieved an average nodal value of $56.60/MWh in 2020. Congestion in the first quarter, driven in part by oil and gas drilling in the Delaware Basin, drove the nodal price up for this West Texas wind project, causing entire months to average as high as $260/MWh.
The driver behind this price spike was localized congestion, which elevated prices at this particular location and suppressed them elsewhere. Coincidentally, the least valuable project in 2020 was also a wind farm in ERCOT West; it realized an average real-time LMP of less than $1/MWh in 2020.
Being on the right side of congestion will continue to be a key determinant to a project’s financial success.
3. Resilient projects lead with a competitive edge.
The fact that cold weather can cause wind farm outages due to the accumulation of ice on turbine blades is not new. Recently, images of iced over blades on non-generating wind turbines have flooded media outlets, but a similar event happened in late October 2020.
In late October 2020, an ice storm affected parts of Texas showing how projects that planned for extreme weather events are best positioned to take advantage of price spikes.
Several projects were forced to stop production during the ice storm due to ice accumulation on wind turbine blades. Projects that kept generating benefited from high wind speeds and elevated power prices, while projects that shut down earned little real-time revenue.
As a result, neighboring projects with a similar wind resource earned very different levels of merchant revenue. An example is shown above: the as-generated value of power generated by Barton Chapel wind farm at ERCOT North Hub was over 2.5 times than that of Green Pastures Wind, a wind farm located just slightly to the northwest.
Given that the market impact of the ice storm in October 2020 was tiny in magnitude compared to last month’s events, we expect that the recent cold snap drove even larger discrepancies in project value. Both the October ice storm and the February polar vortex underscore how projects that plan for extreme weather events and build resiliency into their systems have a competitive edge.
Given that high prices tend to correspond to extreme weather, clean energy buyers should also be aware that a project’s resiliency during these events has significant financial impacts — and should align incentives in their offtake contracts accordingly.
4. Texas summer price spikes were tame in 2020, but what of 2021?
During the heatwave of the summer of 2019, the ERCOT market saw what was at the time unprecedented price volatility, with real-time prices reaching as high as $9,000/MWh for the first time in the market’s history. This was great news for renewable energy project owners and offtakers, so long as their project was generating during the handful of price spikes. The same is true during last month’s events, during which prices reached $9,000/MWh for days at a time.
As we detailed in the 2020 P99 Hedge That Wasn’t white paper, the situation was and will continue to be quite painful for any renewable energy project with a firm volume contract in place that did not generate enough energy to meet their firm volume commitments during price spikes.
By comparison, in the summer of 2020, the ERCOT market saw prices that were much lower than in 2019. In August, ERCOT West around-the-clock real-time prices averaged just $33/MWh in 2020, compared to $131/MWh in 2019. The value of both wind and solar projects in ERCOT West, similarly, dropped in August 2020: wind generation was worth just $24/MWh, and solar generation $52/MWh — a 70% and 80% reduction in value, respectively, from August 2019.
As a result, projects and offtakers that benefited from the prior year’s volatility had a much less profitable summer. For renewable energy projects with firm volume commitments, however, summer 2020 offered a reprieve from the pain of 2019 as lower weather-driven volatility resulted in more stable contract performance.
Last month’s events demonstrate that critical weather events are not isolated to one month or one season. Whereas 2019 saw summer spikes, 2021 has already seen record-breaking winter peak load records that resulted in new record-breaking prices in Texas.
We will all be watching the weather closely in 2021. This is particularly true for offtakers attempting to hedge market rate exposures and projects with fixed volume swaps, as they remain highly sensitive to price volatility and whether or not the sun is shining or wind is blowing during any exceptionally high-priced hours.
5. Wind energy prices at SPP North Hub bottom out during low-demand periods.
The average real-time value of wind generation at SPP North was worth $1/MWh over the entire month of November 2020. This record-low price point was driven by a combination of above-average wind speeds, below-average demand, and more than 1.6 GW of new wind build coming onto the grid in 2020.
The graphic above shows that the value of wind generation was in fact well below $0/MWh in many locations across the ISO, if settled in the real-time at SPP North Hub.
This low price month stands in sharp contrast with the events of last month, where prices were regularly in the hundreds or thousands of dollars as cold gripped much of the region.
With more than 3 GW of additional wind capacity planned to come online in 2021 in the SPP ISO, we will be watching to see if record low generation-weighted prices continue during periods of low demand.
6. Solar in CAISO stabilizes after five years of shape decline.
After five years of consistent degradation in shape scalar (the ratio between the as-generated value of power and the around-the-clock value of power), CAISO solar projects bounced back in 2020 with a slight uptick in value.
While solar shape remained near record lows of around 80% of the ATC price, this is a material uptick from the prior year’s value, which for many California solar projects was below 70%. The increase is attributable in part to price spikes that were concurrent with solar generation during the heatwave in August.
Going forward, we will be watching the California solar value closely as hundreds of MWs of battery storage capacity come online in 2021 and increase the grid’s ability to shift solar generation away from the hours of abundant sunshine.
7. Basis in SPP is a less sore subject.
Basis, or the difference between the LMP at the project node and at the relevant hub, is a significant contributor to a project’s bottom line. Historically, wind projects in SPP have struggled with significant basis impacts to revenue, with nodal LMPs often spending many hours at or below zero.
In 2020, the average as-generated basis cost for wind projects in this area was $3/MWh, meaning that on average over the year market price at the project’s node was $3/MWh lower than the relevant hub price when weighted by project generation. This is a significant improvement from years prior, in which basis costs reached as high as $20/MWh.
While 2020 saw node-to-hub basis improve across SPP wind projects, it’s unclear whether this trend will continue. Developers that site their projects in locations that minimize basis risk or that employ downside-protection options will be best positioned for long-term success.
Buying and selling solar energy is complicated by constant changes in weather, congestion on nearby transmission wires, project downtime for maintenance or repair, and other market conditions outside of an owner or buyer’s control.
REsurety has identified four key insights on how solar markets performed in 2020, as well as the data behind them.
1. Texas solar outshines all others.
The value of utility-scale solar project generation in 2020 ranged from around $19/MWh in MISO (Midcontinent Independent System Operator) to roughly $31/MWh in ERCOT (Electric Reliability Council of Texas). Here, value is measured as the value of project generation, sold at the real-time Locational Marginal Price (LMP) at the hub, and where project generation is either observed or modeled depending on data availability.
Overall, realized values hovered relatively close to the market average of roughly $25/MWh at the hubs reviewed. Only projects with a full year of data (and thus had become fully operational prior to 2020) were included in our analysis.
The highest realized prices of 2020 were in ERCOT, where solar is expected to—but hasn’t yet—come online in impressive numbers in the next couple of years. Solar projects that are able to be built and fully operational sooner rather than later will likely take advantage of a positive solar shape scalar (defined as the ratio between the as-generated value of power and the around-the-clock value of power). However, solar shape degradation is sure to arrive in Texas as it already has in California.
Here is a summary of project values observed in 2020 across various markets. Note that ATC refers to the around-the-clock hub price:
2. Localized congestion chooses winners and losers.
The highest-value solar project in ERCOT this past year was in far west Texas. In spring 2020, “West of the Pecos Solar” benefited from local congestion that elevated node-to-hub basis to a high of over $80/MWh in March.
Unfortunately for nearby solar projects, the benefits of congestion were not widespread; most other projects saw limited benefit from the localized congestion, and some were negatively impacted. Being on the right side of congestion will continue to be a key determinant to a project’s financial success.
3. Are we past the days of $9,000/MWh pricing?
Most project owners and operators in Texas remember that exceptional summer of 2019 when real-time power prices met their upper limit of $9,000/MWh for the first time in ERCOT’s history.
This was welcome news for solar project owners and offtakers, provided the project was operational and generating during those exceptionally high-priced hours.
The situation was painful for any renewable energy project (wind or solar) that was not generating due to operational outages or poor resource availability and still had to meet any firm volume commitments (as detailed in our P99 Hedge That Wasn’t white paper).
This is precisely what happened on Aug. 15, 2019, between 3 p.m. and 4 p.m. Cloud cover developed over much of West Texas, causing a drop in solar generation that contributed to real-time power prices reaching $9,000/MWh. Solar projects with a fixed volume swap and affected by the cloud coverage were left in a very painful financial position, as they would need to pay market prices for the generation they were short under their contract.
In 2020, Texas experienced significantly lower power prices. ERCOT West ATC real-time prices averaged $33/MWh in August 2020, compared to $131/MWh in August 2019, a 75% drop.
Solar-specific value dropped as well: Solar generation in the ERCOT West region was worth just $52/MWh in August 2020, an 80% reduction in value from August 2019.
One thing is clear: Projects and offtakers that benefited from 2019’s volatility were much less profitable in 2020. For solar projects with firm volume commitments, summer 2020 offered a reprieve, as lower weather-driven volatility resulted in more stable contract performance.
Projects and offtakers alike in Texas will be watching the weather closely in 2021, as they remain highly sensitive to price volatility and whether or not their projects are performing as expected during high-priced hours.
4. Solar in CAISO stabilizes after five years of shape decline.
After five years of consistent degradation in shape scalar, solar projects in CAISO (the California Independent System Operator region) bounced back in 2020 with a slight uptick in value.
While solar shape remained near record lows of around 80% of the ATC price, this is a material uptick from the prior year’s value, which for many California solar projects was below 70%. The increase is attributable in part to price spikes driven by the heatwave in August.
Going forward, we will be watching this shape value closely as hundreds of megawatts of battery storage capacity come online in 2021 and increase the grid’s ability to shift solar generation to meet market demand.
First used with wind projects, a pgPPA manages weather-related risk by settling a facility’s energy transfer based on a proxy generation index, rather than on actual metered generation. Operational risk shifts from buyer to seller.
An innovative financing deal is the latest evidence that solar is entering the mainstream among big institutional investors.
Lightsource bp secured what’s known as a proxy generation power purchase agreement (pgPPA or Proxy Gen) with the Capital Solutions unit of Allianz Global Corporate & Specialty (AGCS), in partnership with Nephila Climate.
The pgPPA covers electricity generated by Lightsource bp’s 153 MW Briar Creek solar farm, under construction in Navarro County, Texas.
In simple terms, a pgPPA is a renewable energy contract designed to manage weather-related risk. In practice, it settles energy transfer from a facility based on a proxy generation index, rather than on the metered generation. That means proxy generation is an hourly index that determines the volume of energy that a project would have produced if it had been operated as specified by the developer or owner.
The arrangement hinges on both the owner and the offtaker agreeing on a set of weather metrics to establish the proxy generation component. In the case of Lightsource bp’s Briar Creek facility, REsurety Inc. will serve as the calculation agent over the life of the contract.
The pgPPA reflects the fact that solar “can stand on its own two feet” and not be so tied either to a purchase power agreement or public policy directive, said Lee Taylor, REsurety’s founder and CEO in an interview with PV Magazine USA.
Taylor said that the pgPPA structure emerged a few years ago in the wind energy sector, and variations are common in agribusiness, as well as ski resorts, among other weather risk-related markets. One of the technique’s first uses in renewable energy was with the 178 MW Bloom Wind facility in Kansas, part of the Southwest Power Pool. U.S. Capital Power operates Bloom Wind under a 10-year fixed price contract with Allianz Risk Transfer that covers 100% of the project’s output.
Under the contract, signed in 2016, Capital Power swaps the market revenue from the wind project’s generation for a fixed annual payment over a period of 10 years. The agreement secures long-term predictable revenues and mitigates generation volume uncertainty related to the intermittent nature of the wind resource.
Taylor said that similar structures have been used on wind projects in PJM and ERCOT in the U.S., as well as in Australia. The Briar Creek deal is considered to be the technique’s first use in a U.S. solar project.
“This deal is a great example of the evolution of renewable energy products here in the U.S.,” said Kevin Smith, CEO of Lightsource bp in the Americas. He said that innovative power contract structures such as virtual and pgPPA’s are “valuable tools we can leverage to meet the needs of our corporate partners, manage risk, and continue to finance and build new solar projects.”
Ariane West, Director of Structured Finance, Nephila Climate, said that risk transfer approaches “are essential to support investment and financing of infrastructure on the scale needed to achieve zero carbon targets.”
PPAs and related structures
Purchase power agreements are commonly used structures between a solar facility’s owners and an energy offtaker, often a utility or large manufacturer. In a variation known as a virtual PPA, contract terms focus on the amount of energy the facility delivers to the grid. Typically, the quantity is measured by an electrical meter at the point of interconnection. By settling the energy delivery at the interconnection point on an “as generated” basis, the buyer is exposed to a number of operational risks.
In a pgPPA, the focus is the amount of energy that should have been delivered to the grid had the plant operated according to equipment efficiency factors and operational best practices. The approach shifts operational risk away from the offtaker and onto the seller.
The pgPPA measures the actual wind or solar resource at the facility. It then runs that measurement through an agreed-to formula that estimates how many megawatthours should have been produced given the facility’s size and operations under best practice standards.
In the case of Briar Creek solar, REsurety is providing the hourly solar radiance data, which will be managed using PVsyst photovoltaic software.
The Briar Creek solar farm is about 40 miles south of Dallas, and is expected to start commercial operation at the end of 2021.