Carbon accounting frameworks guide policy and decision-making around investments in renewable energy, making them critical to understand in the context of real-world grid operations. In the absence of empirical work assessing the effects of intra-regional congestion on carbon emissions, ongoing policy design assumes that transmission congestion within grid boundaries can be ignored. In this work, we aim to test this assumption by quantifying the frequency and severity of intra-regional congestion and its impacts on carbon emissions and prominent carbon accounting frameworks. This analysis is done in both PJM and ERCOT using nodal locational marginal emissions data. Through several case studies, we find that load that is 100% hourly-matched through load-shifting will often result in significant net operational emissions, and sometimes even increase net emissions relative to annual-matching. This work demonstrates that, in the absence of robust transmission expansion, grid-region boundaries are insufficient to ensure hourly-matching is effective. Impacts of intra-regional transmission congestion are shown to be vital components of effective carbon accounting frameworks, calling into question frequently made assumptions ignoring intra-regional congestion in studies and policy proposals.
A view of Q2 2024 U.S. renewable energy performance
REsurety creates the State of the Renewables Market report every quarter to provide readers with data-driven insight into the value and emerging trends of renewable generation in U.S. power markets. Please fill out the form to access the full report, the Editor’s Note is below.
Maha Mapara Analyst Senior Analyst, Analytics Services
Devon Lukas Lead Analyst Associate, Analytics Services
Carl Ostridge Editor SVP, Analytics Services
Deliverability: Can Clean Energy Reach Consumers?
Clean energy generators are the fastest growing sources of new energy on grids across the country. But if the impact of those new projects is going to be maximized, and utilized meaningfully in hourly matching carbon offset techniques, the country also needs to invest large sums in improving transmission infrastructure to get the clean energy to load centers. There have been a couple of recent announcements aiming to speed up the development of much-needed transmission (e.g. FERC Order 1920 and Department of Energy TSED funding), but how much of a problem is transmission currently?
To answer this question, we’ll use the concept of “deliverability” – in other words, how much clean energy can reach consumers in a given location. The concept of deliverability is already built into the market prices that system operators publish. There are three components to Locational Marginal Prices (LMPs); energy, congestion, and line losses. Line losses tend to contribute relatively little to the overall prices, and so we can use the difference in LMPs between two locations to estimate the deliverability of the energy. When the LMP at a generator diverges materially from the LMP at the load center, this is a sign that the location is experiencing congestion – either high prices that encourage generation, or low (even negative) prices resulting in renewable generator curtailment.
For this analysis, we’ve defined power as “deliverable” if the LMP at the generator is within 10% of the LMP at the load center. Renewable generation output during periods with greater than 10% LMP divergence is likely subject to congestion, and is therefore considered undeliverable. This is a somewhat simple metric, but it aims to boil down a complex issue into something digestible and relevant; after all, deliverability is a key component in the developing hourly matching frameworks.
In Figure 1, the 12-month trailing average of deliverability is shown for clean energy generators in ERCOT and PJM and load centers in Houston and Chicago, respectively. Historically, only between half and two-thirds of clean power is “deliverable” to these major load centers. This highlights that transmission congestion has been, and still is, a meaningful issue. It’s also notable that despite higher penetration levels of wind and solar in ERCOT, the deliverability of clean energy to Chicago has dropped more rapidly since the start of 2021.
Figure 1: Trailing 12-month average clean energy deliverability to Houston and Chicago.
When we look a little deeper at the ERCOT deliverability, separating the results for wind and solar projects, the story of the flatter deliverability trend becomes clearer. The deliverability of wind in ERCOT has been trending downwards over the past few years, while solar has trended upwards. There are two factors in favor of solar’s better deliverability: timing and location. Solar’s on-peak generation coincides with higher load, leading to fewer congestion issues. Furthermore, the operational solar fleet is more geographically dispersed compared to the wind fleet, meaning fewer solar projects are subject to major transmission constraints (such as in the Texas Panhandle and Gulf Coast).
Table 1: Deliverability of ERCOT wind and solar energy to Houston.
Of course, these trends will evolve over time as more clean energy is added to the grid, thermal generators are decommissioned, energy storage capacity expands, gross and net load profiles evolve, and transmission either stays constant or gets upgraded. This metric is just the beginning of our efforts to analyze this complex issue. A REsurety whitepaper on deliverability is in the works, covering more regions and diving deeper into the underlying causes and resulting carbon impacts.
A view of Q1 2024 U.S. renewable energy performance
REsurety creates the State of the Renewables Market report every quarter to provide readers with data-driven insight into the value and emerging trends of renewable generation in U.S. power markets. Please fill out the form to access the full report, the Editor’s Note is below.
Devon Lukas Lead Analyst Senior Analyst, Analytics Services
Carl Ostridge Editor SVP, Analytics Services
Record-Breaking Winter for Solar: Behind The Scenes
Solar output in ERCOT has been in the news as of late, with the buzz around the record-breaking 17.2 GW peak on February 19th amplified by the 18.7 GW peak on March 28th. While impressive, these records are actually not broken as often, or by as much, as one might initially expect given the amount of recent solar buildout. The current generation record would be 300 MW higher were it not for the complex interactions between the weather, transmission infrastructure, and tax incentives.
First, and perhaps most obviously, the weather impacts renewable generation and demand, and when there’s too much of the former and not enough of the latter, renewable projects are curtailed. Net load (total load minus renewable generation) is a useful metric to highlight this behavior. Figure 1 shows solar curtailment as a function of net load for Q1 2024. It’s clear that as net load drops below 20 GW, solar generation starts to be curtailed, increasing quickly as net load reduces further. These grid-wide supply and demand balancing issues that lead to renewable energy curtailment also play out on a local level, caused by transmission constraints. Even if there’s enough demand overall on the grid, if the renewable energy is located behind a transmission constraint, curtailment will still happen. Finally, there’s the tax incentives – wind projects tend to receive the Production Tax Credit (PTC) while solar projects tend to receive the Investment Tax Credit (ITC). Since the PTC is earned on a per megawatt-hour basis, many wind projects continue generating even when wholesale prices are negative. On the other hand, ITC-qualified solar projects will curtail as soon as wholesale prices become negative.
Figure 1: Net Load and Solar Curtailment, January – March 2024. Record-breaking periods shown in blue, missed records shown in green.
So, in terms of setting solar generation records, there needs to be an alignment of these variables – high solar generation potential, relatively low wind generation, relatively high load, and no meaningful transmission constraints. Figure 2 shows two days in February with different conditions and different outcomes. The first is February 19th, when there were favorable conditions and a new record was set – the skies were clear, wind output was low during the day, and net load stayed above 20 GW. A few days later on February 24th, conditions were not as favorable – skies were clear in the morning, but wind output was increasing and net load dropped below 20 GW. This meant solar projects were curtailed and while a new solar generation record 300 MW above the February 19th level could have been set, it was not.
Figure 2: Actual and Uncurtailed Solar and Wind on February 19th, 2024 (left) and February 24th, 2024 (right) Compared to Net Load (load minus actual wind and solar generation).
It’s also important to note the seasonality in these trends. The time of year makes these solar output records more unlikely – the first quarter of the year tends to be windy and load levels are on the low side too. As the summer approaches, wind generation will be lower on average and load will be higher. More solar projects will also likely be commissioned by then, so expect more records to be broken (and perhaps more frequently). Looking further forward, it will be interesting to see if some of the new solar projects elect for Production Tax Credits and therefore start to operate during periods of negative prices. If so, expect even more records to be set.
However, lost generation due to curtailment isn’t all doom and gloom. By definition, renewables make up a large proportion of the grid’s generation during periods of low net load and curtailment. For corporate buyers measuring their impact in emissionality terms, this means the ‘lost’ emissions impact due to curtailment is relatively small – most of that curtailed energy would have displaced other clean fuels (rather than fossil generators). This is especially true during periods of low net load, where high wind generation will keep marginal emissions rates low regardless of the level of solar curtailment. Figure 3 shows the average ERCOT Locational Marginal Emissions rate declining as renewable energy curtailments increase.
Figure 3: Daily Average ERCOT LME (kgCO2e / MWh) and Renewable Energy Curtailment in January, 2024.
As always with power markets, there’s a lot more going on behind the headlines of record breaking solar output.
In addition to downloading the report, you may want to watch a recording of a webinar on the Q1 report that we hosted in May, with the editor, Carl Ostridge, and lead analyst, Devon Lukas. They shared findings, insights, and hosted a live Q&A.
A view of Q4 2023 U.S. renewable energy performance
REsurety creates the State of the Renewables Market report every quarter to provide readers with data-driven insight into the value and emerging trends of renewable generation in U.S. power markets. Please fill out the form to access the full report, the Editor’s Note is below.
Devon Lukas Lead Analyst Senior Analyst, Analytics Services
Carl Ostridge Editor SVP, Analytics Services
Emissions (Rates) Ignore (ISO) Borders
As of the end of 2023, Locational Marginal Emissions data is available for all seven deregulated ISOs in the U.S. That additional data coverage is reflected in the later parts of this report. Here, we’re going to dig into what the data can tell us about the current state of the different ISOs and how it can shine a light on the current hydrogen-hourly matching debate.
All the data included in this analysis is for the period November 2022 – October 2023.
1. Renewables projects in CAISO, and particularly solar, had the lowest environmental impact.
There’s already a lot of solar power installed in California, and that means during the day when the sun is shining, solar power is often the marginal generator. That means incremental solar generation is displacing clean megawatt-hours from other solar projects, not fossil-based generators. The average renewable energy project in CAISO during this 12-month period displaced only 234 kgCO2e/MWh. That’s less than half the emissions impact of the average renewable energy project in PJM.
Figure 1: Locational Marginal Emissions Rates for wind and solar projects (kgCO2e/MWh), November 2022 – October 2023. Average, P5 and P95 values are shown.
2. PJM is where renewable energy has the biggest environmental impact.
A combination of relatively low penetration rates for renewables and fewer transmission constraints means there’s an outsized impact for any new wind or solar project in the PJM footprint because it is often displacing fossil-based generators and rarely displacing other renewables. On average, a renewable energy project in PJM displaced 25% more CO2 than an equivalent project in SPP and almost 40% more than projects in ERCOT.
3. There is a huge range of emissions rates within most ISOs.
It’s perhaps more intuitive to make sense of the differences in average emissions impacts between ISOs – each has its own unique generation stack, load profile, and set of connections with neighboring regions, resulting in different emissions rates for renewables. However, there’s an even bigger range of emissions rates within these regions. This is primarily driven by the unique local transmission constraints within each region and how each of these constraints affects the ability of renewable generation to meet load. Two examples of localized variability in emissions impact are shown in figures 2 and 3. In both southern Oklahoma and western Minnesota, the emissions impact of wind projects is reduced due to local transmission constraints and congestion.
Figure 2: Locational Marginal Emissions, Oklahoma Wind Generators, November 2022 – October 2023.
Figure 3: Locational Marginal Emissions, Iowa and Minnesota Wind Generators, November 2022 – October 2023.
This last point about intra-regional variability is interesting for a number of reasons, but one to specifically call out here is the current debate around the IRS guidance for hourly matching of renewables for hydrogen electrolyzers under Section 45V of the Internal Revenue Code. The latest IRS proposal requires hourly matching of electrolyzer consumption with renewable energy procured within the same ‘region’. While the hourly matching regions don’t precisely match ISO boundaries, they’re pretty close. Therefore, the intra-regional variation in emissions impact for renewable energy projects would likely translate directly to the real-world emissions associated with ‘green’ hydrogen. An electrolyzer could procure renewable energy from a high-performing project in the region and avoid a lot more carbon than the electrolyzer consumes. The more worrying possibility is the opposite scenario – buying power from an underperforming project could mean that the hydrogen produced is actually far from ‘green’.
In addition to downloading the report, you may want to register to attend a webinar on the topic on Wednesday, February 7 at 1pm ET with the editor, Carl Ostridge. He’ll share findings, insights, and host a live Q&A.
A view of Q3 2023 U.S. renewable energy performance
REsurety creates the State of the Renewables Market report every quarter to provide readers with data-driven insight into the value and emerging trends of renewable generation in U.S. power markets. Please fill out the form to access the full report, the Editor’s Note is below.
Devon Lukas Lead Analyst Senior Analyst, Analytics Services
Carl Ostridge Editor SVP, Analytics Services
A Tale of Two Technologies
When I think of Southwest Power Pool (SPP) I think of wind. Wind met almost 40% of SPP demand in 2022 and new output records have been consistently set over the past couple of years. When I think of SPP I don’t think of solar, though. Solar met less than 0.5% of SPP demand in 2022. And I’ve always found that a little surprising considering the southern SPP footprint has some of the best solar resource in the country (ref: NREL). Maximum solar output this summer in SPP was only 30 MW higher than 2022 while the equivalent metric in ERCOT increased by more than 3,500 MW.
The abundance of wind generators and the lack of solar also means the two technologies look very different when considering two important metrics – the monetary value and the decarbonization impact of each MWh.
Figure 1 shows the capture rates (the value of the wind or solar-weighted MWh compared to around-the-clock MWh) for both price and emissions intensity. We see similar trends in both – wind is capturing less and less of the available monetary value and avoiding less and less CO2 while the opposite is true for solar.
Figure 1: Price and Emissions Intensity Capture Rate, 12-month rolling average. Uses representative modeled wind and solar generation data. February 2021 excluded.
To understand what’s causing this we can look at the month-hour average prices and emissions rates over the past four years. We see that both prices and emissions rates are highest during the summer afternoons. During these times load is high and often wind output is low, meaning the marginal unit is a thermal generator with higher emissions rates. Of course, these are the same hours when solar output is peaking and that correlation leads to high solar value (in $ and CO2 avoidance terms) compared to an around-the-clock generation profile. Conversely, the low prices and low emissions rates are occurring (not coincidentally) in hours of high wind output and this drives the prices and emissions rates lower.
Figure 2: Average Real-Time Price and Emissions Rate 12×24, SPP South.
On the face of it, this means adding solar to SPP would be a win-win, it would capture relatively high value power prices and would displace thermal generators more often, avoiding more carbon emissions. In Q3 of this year, solar was worth more than $50/MWh at South Hub while wind was worth closer to $20/MWh. During the same period, solar generation also had a 40% larger emissions reduction impact compared to wind.
Table 1: Price and Emissions Values for Wind and Solar in Q3 2023.
So why aren’t more solar projects being built? There are a number of challenges, but transmission is a considerable one. The interconnection queue is long and growing thanks to the IRA, and getting an interconnection agreement often requires developers to share large upgrade costs. Further, this analysis reflects the hub values for prices and emissions. Wind projects in SPP suffer some of the worst price basis in the country with some projects seeing $10-20/MWh annual nodal discounts vs. the hub. Investment tax credit (ITC)-qualified solar projects would likely need to curtail output as soon as prices reach negative territory while production tax credit (PTC)-qualified wind projects tend to continue operating far beyond that point.
There’s currently value available for solar in SPP but only if project developers can navigate the complex issues related to transmission, interconnection, and congestion.
A view of Q2 2023 U.S. renewable energy performance
REsurety creates the State of the Renewables Market report every quarter to provide readers with data-driven insight into the value and emerging trends of renewable generation in U.S. power markets. We use our domain expertise in power markets, atmospheric science, and renewable offtake to analyze thousands of locations and summarize key findings here. All of the data behind this analysis is curated by REsurety’s team of experts and available via our software products. It includes aggregated metrics for wind and solar projects operating in the U.S. All summaries are calculated using hourly-level data, and all energy-weighted price metrics are calculated using concurrent weather-driven generation and energy price time series. Please fill out the form at the bottom of the page to access the full report, the Editor’s Note is below.
June in Texas: High Heat, Not So High Power Prices
I recall the buzz during the summer of 2019 when power prices in ERCOT reached $9,000/MWh for a few hours and the speculation about how prices may have been lower with more solar on the grid. Fast forward to 2023. The hot topic to start the hot summer is instead how power prices may have been even higher without the observed solar generation. Solar energy’s contribution to grid resilience during this summer’s heat waves has even become mainstream news, with headlines about the absence of the power supply scares of previous summers.1
Indeed, solar capacity in ERCOT has grown over the last few years. Observed hourly solar generation regularly approached 13,000 MWh heading into this summer, compared to a maximum of approximately 10,000 MWh the same time last year (Figure 1). However, despite record breaking demand and a few hours of scarcity prices in June, the average monthly prices remained below the values from last summer (Figure 2). The average power price in June 2023 at ERCOT North Hub was $2 less than in June 2022 despite exceeding the monthly peak demand record by over 4,000 MW.2
Figure 1: Observed Hourly Solar Generation in ERCOT
Figure 2: Average Monthly Power Prices at ERCOT North Hub.
REsurety estimates that the average power price in ERCOT this June would have been nearly double the observed value without the additional solar generation. We also estimate that solar resources would have captured 27 percent more of this higher average monthly price, while wind resources would have captured 14 percent less.
Continued growth in solar capacity is expected to further degrade the capture rates for solar in ERCOT, while supporting capture rates for wind and keeping average prices lower for consumers. REsurety’s Weather-Smart fundamentals power price model shows reductions in solar value as solar buildout ramps up and the highest price hours are pushed out to the early mornings and evenings. At the same time, the reduction in power prices during afternoon hours also helps to limit downside risk to wind generation value. The lowest wind capture rates tend to occur in months that experience periods of low wind resource coinciding with periods of high demand from high temperatures.
We continue to watch how solar energy resources will perform with more hot weather still to come. Regardless of how the rest of this summer turns out, the impact that increasing solar penetration is having on markets like ERCOT is already apparent, and increasingly suggests that the near future is fundamentally different from the recent past. We will keep sharing our data findings in these quarterly reports as well as trends and thought leadership on our corporate blog.
A view of Q1 2023 U.S. renewable energy performance
REsurety creates the State of the Renewables Market report every quarter to provide readers with data-driven insight into the value and emerging trends of renewable generation in U.S. power markets. We use our domain expertise in power markets, atmospheric science, and renewable offtake to analyze thousands of locations and summarize key findings here. All of the data behind this analysis is curated by REsurety’s team of experts and available via our software products. It includes aggregated metrics for wind and solar projects operating in the U.S. All summaries are calculated using hourly-level data, and all energy-weighted price metrics are calculated using concurrent weather-driven generation and energy price time series. Please fill out the form at the bottom of the page to access the full report, the Editor’s Note is below.
For me, the story of 2022 was the high average power prices across the U.S. Emphasis on average because the high prices were not driven by individual large weather or market events like Winter Storm Uri in 2021. Yes, there were some weather-linked events, but these really didn’t move the needle at the annual level. The real driver in 2022 was the underlying price of natural gas – Henry Hub prices started the year at ~$4/MMBtu (already high compared to the last few years) and peaked close to $9/MMBtu in the summer. That’s by far the highest natural gas price seen in the post-shale era of the last 14 or so years.
Figure 1: Historical Henry Hub Natural Gas Spot Prices ($/MMBtu).
Natural gas is often the marginal fuel in many regions and there’s a strong correlation between natural gas prices and power prices as shown in Figure 2. The historic natural gas prices during 2022 also resulted in power prices reaching their highest annual average in at least the last decade (Winter Storm Uri’s influence in February 2021 excluded).
Figure 2: Natural Gas and Power Prices indexed to 2011-2022 averages (Feb 2021 excluded).
Those high prices led to large payouts to merchant projects and clean energy buyers. For example, a typical 100 MW wind project with a $30/MWh PPA settling at ERCOT West would’ve paid more than $2M to their buyer by the end of the year. An equivalent vPPA settling at SPP South would’ve paid out more than $3M.
Now, fast forward to Q1 2023 and the world looks very different. Gas prices have dropped more than 50% compared to Q4 2022 and 40% compared to Q1 2022. Power prices in most markets have seen similar decreases, down 20-50% compared to Q1 of last year. That means the same vPPAs that were paying large sums to buyers throughout 2022 are now back to paying the projects. In some cases, buyers cut checks to projects in Q1 that exceeded the checks that they received during the whole of 2022.
Table 1: Example Wind and Solar vPPA settlements for calendar year 2022 and Q1 2023
The volatility seen in commodity and power markets in the past 18 months is expected to continue. Natural gas fundamentals, new generation interconnection, supply chain challenges, geopolitical turmoil, and increasingly extreme weather are expected to continue causing large ups and downs in the markets and that, of course, means ups and downs for those buying and selling power.
To understand the contributions of the three primary drivers of changing prices and volatility – grid composition, commodity prices, and weather – REsurety publishes Weather-Smart fundamentals power price forecasts each quarter. For the next 20 years the forecasts account for multiple commodity scenarios and for each of those scenarios models how the grid and market will reach under weather conditions representing each of the past 40 years. For example, we forecast this summer’s prices under ‘mid’, ‘low’, and ‘high’ gas scenarios and if the heat of 2011 or the relatively mild weather of 2007 was repeated (and every set of summer conditions in between). This provides a unique view of how both the commodity prices and weather drive market outcomes.
The model predicts there’s approximately a 3x range between the highest and lowest prices averaged for the remainder of 2023. That’s the difference between having a vPPA pay out to the buyer at similar levels to 2022 or continue to pay out to the project in line with Q1 of this year. With this level of volatility, the clichéd investment disclaimers certainly ring true – “past performance is not a guarantee of future performance and prices may go up as well as down.”
At REsurety we’ll be keeping a close eye on how both the commodity markets and weather unfold over the coming months and keeping our Weather-Smart forecasts up to date with the latest data.
A view of Q4 2022 U.S. renewable energy performance
REsurety creates the State of the Renewables Market report every quarter to provide readers with data-driven insight into the value and emerging trends of renewable generation in U.S. power markets. We use our domain expertise in power markets, atmospheric science, and renewable offtake to analyze thousands of locations and summarize key findings here. All of the data behind this analysis is curated by REsurety’s team of experts and available via our software products. It includes aggregated metrics for wind and solar projects operating in the U.S. All summaries are calculated using hourly-level data, and all energy-weighted price metrics are calculated using concurrent weather-driven generation and energy price time series. Please fill out the form at the bottom of the page to access the full report, the Editor’s Note is below.
Carl Ostridge SVPof Analytics Services
Editor’s Note:
For Renewables, Timing is Everything
The final quarter of 2022 closed out with some extreme weather across most of the country and while lots of comparisons were quickly drawn against 2021’s Winter Storm Uri, December of 2022 also provided useful insights into the changing dynamics of power markets as renewable energy penetration rates increase. While the impact on market prices was smaller overall compared to Uri, one of the most interesting outcomes from the winter weather was present in ERCOT and highlighted the fact that timing is everything when it comes to capturing value from renewable energy assets.
The map in Figure 1 shows the “capture rate” potential of solar assets across the ERCOT footprint in December, 2022. Capture rate is the ratio of generation-weighted price and simple average price during the period in question and shows how much of the average price is ‘captured’ by, in this case, solar assets. Immediately visible is the interesting geographic trend across the ERCOT footprint, with the highest solar capture rates occurring in the east and west extremities while the lowest capture rates occur in the center. To understand what’s driving this, we need to look at the underlying data for one specific day.
Figure 1: Solar Capture Rate at ERCOT North Hub RT, December 2022
Figure 2: Modeled Generation for 100MW Solar Assets Located in the Houston and Midland Regions & Market Prices, December 23rd, 2022
Figure 2 shows the hourly average real-time market prices on December 23rd, 2022 as well as the generation of two hypothetical solar assets; one in west Texas and another close to the Houston area. The highest prices during this day occurred early in the morning and in the evening, meaning that most of the solar output during December 23rd did not coincide with the high prices. This leads to the very low overall capture rates in December, ranging from ~45-60% across ERCOT. But importantly, the lower prices during the day are not actually a coincidence – peak solar output has more than doubled since 2020 and there was approximately 8 GW of solar generation during the middle of the day on December 23rd, 2022, enough to move the grid out of scarcity pricing mode and back to more “normal” prices. This dynamic also creates values for locations with early sunrises (in the east) and late sunsets (in the west). The difference in sunrise and sunset times in Midland and Houston on December 23rd was approximately 30 minutes, but that was enough to secure an additional $50/MWh of value. Solar assets located close to Houston would have been able to capture the value of the high market prices before the sun came up on most of the existing solar assets further west and prices fell. That $50/MWh difference might not sound like a lot, but considering that solar capacity in ERCOT is predicted to exceed 20 GW by 2025, this type of ‘duck curve’ where solar generation serves to systematically reduce prices during the day is likely to happen with increasing frequency. Therefore, siting solar assets in locations able to naturally take advantage of the ramp hours may become increasingly valuable.
Finally, this shift in ERCOT’s grid mix, price dynamics, and subsequent drop in solar capture rates is predicted by REsurety’s Weather-Smart Fundamentals modeling. REsurety models ERCOT’s grid in 5 different future states, including high storage and net zero, and computes outcomes based on weather data representing the past 40+ years to derive the data in Figure 3 below.
Figure 3: ERCOT Solar Capture Rates Predicted by REsurety’s Weather-Smart Modeling
The average solar capture rate in ERCOT is forecast to drop below 100% by 2024, driven by the type of event we’re highlighting here – solar generation is high enough to reduce prices during the day and scarcity pricing is moved to the early morning and evening hours. As ever, timing will be the key to renewable energy value.
A view of Q3 2022 U.S. renewable energy performance
REsurety creates the State of the Renewables Market report every quarter to provide readers with data-driven insight into the value and emerging trends of renewable generation in U.S. power markets. We use our domain expertise in power markets, atmospheric science, and renewable offtake to analyze thousands of locations and summarize key findings here. All of the data behind this analysis is curated by REsurety’s team of experts and available via our software products. It includes aggregated metrics for wind and solar projects operating in the U.S. All summaries are calculated using hourly-level data, and all energy-weighted price metrics are calculated using concurrent weather-driven generation and energy price time series. Please fill out the form at the bottom of the page to access the full report, the Editor’s Note is below.
Carl Ostridge SVPof Analytics Services
Editor’s Note:
Grid Congestion Hurts Project Economics & The Environment
Project developers know well the perils of transmission constraints and grid congestion when it comes to their project’s economics. If you locate your project at a point on the grid with limited availability to move clean electricity to where it will be consumed, local power prices will be much lower than average prices across the wider grid. This phenomenon is often referred to simply as “basis” but we’ll be more specific here and call it “price basis”. Price basis is bad for project economics for two reasons – first, the project’s merchant revenue (the value of electricity sold to the system operator at the point of interconnection) can be vastly reduced and second, if the project enters into a financial agreement to sell their electricity at a hub price (an aggregate across a large grid area) they may end up owing large sums of money that their merchant revenue cannot support.
The magnitude of price basis is hard to predict and, without investment in transmission or energy storage, tends to get worse over time as more wind and solar projects are added to the grid in locations with high resource availability. Developers and consultants spend lots of time, money and effort building models to analyze historical basis and forecast future scenarios to decide where to build projects and inform their economic outlook.
However, the transmission constraints and congestion that drive price basis also lead to what we’ll refer to as “emissions basis”. When a transmission constraint binds in a region with plentiful wind and solar generators, incremental clean energy (behind the constraint) often curtails other existing clean generators rather than carbon-emitting thermal generators elsewhere on the grid. This leads to emissions basis – wind and solar projects subject to transmission constraints avoid fewer tons of carbon emissions per MWh generated than the grid-wide average. In the absence of additional transmission or energy storage infrastructure, building additional wind and solar facilities in these regions has a diminishing environmental impact. Each new facility contributes less and less to the ultimate goal of decarbonization.
Figure 1: Price basis vs emissions basis for wind and solar projects in ERCOT and PJM (Jan-Jul 2022)
The strong correlation between price basis and emissions basis is highlighted in the plot below. Each point represents a wind or solar project in ERCOT or PJM and the values of price and emissions basis is calculated for the period January to July 2022. It’s clear from the plot that the projects with the highest levels of negative price basis have the lowest environmental impact while those with positive price basis tend to displace significantly more carbon emissions from the grid. Of course, there are many nuances to the data beyond this high-level correlation – trends based on location, technology, time of day and season – that REsurety’s Locational Marginal Emissions data can expose.
REsurety calculates Locational Marginal Emissions values at the nodal level with hourly resolution to provide the information necessary for project developers, investors, and offtakers to make informed decisions about where to build or invest in new projects to maximize their revenues and environmental impact.
We’ve expanded this report to provide information on both the financial and environmental value of wind and solar generation in the U.S. We hope you find this report informative.
REsurety creates the REmap-powered State of the Renewables Market report every quarter to provide readers with data-driven insight into the emerging trends and value of renewables in U.S. power markets. We combine our domain expertise in power markets, atmospheric science, and renewable offtake to analyze thousands of projects and locations and summarize key findings here. All of the data behind this analysis is available via our interactive software tool, REmap. Please fill out the form at the bottom of the page to access the full report, the Editor’s Note is below.
Blair Allen Director, Software Customer Success, REsurety
Editor’s Note:
Node to hub basis* is rapidly becoming one of the most prominent financial risks for renewable developers and clean energy buyers alike. Although not a new issue, it has recently become more visible for two reasons: first, it is getting much worse in many areas with a lot of renewables, and second, clean energy buyers are increasingly taking on basis-risk exposure through contractual terms in PPA agreements. While basis used to be a risk only borne by project developers and investors, now corporates are sensitive to it as well.
In Q2, a handful of renewable-rich regions saw generation-weighted (AsGen) basis worsen by double digit values relative to the 4 year Q2 average. In many cases this was most prominent in areas that were already no stranger to negative basis. In ERCOT South Hub, for example, the average AsGen basis for operating wind projects in Q2 over the last 4 years was -$11 – in 2022 it declined to -$34. In the NP15 region of CAISO, the average AsGen basis for operating solar projects dropped from -$9 over the last 4 years to -$27 in 2022. And in SPP South Hub, operating wind projects saw their 4 year average decline from -$9 to -$31 in 2022.
But hub-level average values only tell part of the story, since basis is inherently a project-specific concern and can vary considerably not only within hub boundaries but across projects only miles apart from each other. For instance, when considering the projects within SPP South Hub last quarter, REmap shows project-by-project AsGen basis values that varied from as low as -$48 to as high as $26. The same extreme divergence played out across different ISOs and hubs, driven by subregional constraints driving a wedge in value between locations on either side of congested areas.
Basis warrants so much attention because it is extremely volatile and has a large impact on investment returns. In addition, it is hard to solve: investment into transmission infrastructure takes years and is extremely expensive. Developers screen for viable greenfield locations to avoid it, investors pore over model results to price it, and now energy buyers are turning to their advisors or tools to understand it better as well. The basis risk sharing clauses increasingly present in PPAs link the developer and clean energy buyer to the project’s basis performance in ways the two groups weren’t before, and the mechanics of that linkage aren’t always well understood. Although its impact ultimately depends on the counterparty and the project-specific contract details that can either worsen or improve exposure, one thing is clear: basis should be on everyone’s radar.
In this Q2 REmap report, we analyze a number of metrics including: shape, capacity factor, and AsGen value of power for renewables domestically. REmap users have real-time access to these metrics and more, including basis analysis, through the map-based SaaS offering.
*AsGen basis is defined in this report as the difference between a project’s AsGen nodal price ($/MWh) and its hub price ($/MWh), where the hub is assumed to encompass the area where the node is located.
The hedge market is offering the same menu of options a year and a half after a sudden cold snap in Texas left some power projects facing huge losses.
However, more attention is being paid to how to cap exposure in extreme scenarios.
Winter Storm Uri was an extreme cold event in late February 2021, centered in Texas but also affecting neighboring states, that was a one-in-10-year or one-in-50-year event, depending on which meteorologist you ask. It was not off the charts, but it involved an extreme level of sustained cold. There were deaths and significant property damage in Texas.
The storm led to a spike in electricity demand, especially for heating, and a shortfall in supply.
The shortfall in supply was driven by a number of factors, but the main driver was power plants froze physically and transmission infrastructure was shut down. These factors affected all types of power plants. The most pronounced effect was on gas-fired generation, but renewables, and wind in particular, were affected as well.
There was a pronounced financial impact in ERCOT because of the mechanism within ERCOT to reward generation during spikes in demand. There are administrative adders to the spot electricity price that force the price of power to go to a cap, incentivizing supply when demand spikes. At the time, the cap was $9,000 a megawatt hour. The result was that a spot market in which the price for electricity is often in the $20 to $40 range per MWh, was suddenly pricing power at $9,000 a MWh for three days.
REsurety creates the REmap-powered State of the Renewables Market report every quarter to provide readers with data-driven insight into the emerging trends and value of renewables in U.S. power markets. We combine our domain expertise in power markets, atmospheric science, and renewable offtake to analyze thousands of projects and locations and summarize key findings here. All of the data behind this analysis is available via our interactive software tool, REmap. Please fill out the form to access the full report, the Editor’s Note is below.
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Blair Allen Director, Software Customer Success, REsurety
Editor’s Note: As the first quarter of 2022 concludes, we reflect on historic highs and historic lows. Another record in ERCOT marks the quarter’s passing, just as one did a year ago following the market events of February 2021. However, unlike the soaring prices of last year, this record involves a prolonged period of negative pricing, and another turn in a developing plotline we commented on last quarter. Please fill out the form below to access the report.
Consider this comparison: in February 2021 ERCOT West Hub (along with others) settled at the market price cap of $9,000/MWh for three days; in February 2022 ERCOT West Hub saw a two day period where prices never rose above $0/MWh. Mild demand coupled with sustained periods of high wind and solar generation created the conditions for this negative pricing event, though these conditions weren’t isolated to only those few days. In fact, by the end of the quarter, West Hub would more than double the number of negative-priced hours than were seen in Q1 the year prior.
One impact of this increasing frequency in negative pricing is rising levels of curtailment, particularly among solar projects which, unlike wind, don’t benefit from the production tax credit and are less likely to operate below $0/MWh. For example, using the modeled energy in REmap, which tells us how projects could have performed based on underlying wind/solar resource availability, last quarter West Texas solar projects saw anywhere from 20 to 30% of their potential hourly production for a given month fall in negatively priced hours. However, in reality these projects weren’t operating at their potential capacity in these intervals, and either shut down or significantly ramped down production.
Another important angle to consider: whereas for the last few years hourly negative prices at West Hub were evenly split between on-peak and off-peak hours during this time of year, this year saw that balance shift to 60/40 in favor of on-peak hours. The cause for this shift is clear: increasing amounts of solar capacity means that low pricing is no longer just following the production profiles for wind, and is coinciding more regularly with the rise and fall of solar energy.
Looking ahead, as seasons change into summer conditions so too do we expect a change in the volume of negative pricing. An increase and shift in demand– which will steadily move more towards the mid afternoon as air conditioning ramps–and a decline in wind production at the same time should converge to steadily mitigate on-peak negative price frequency. Q2 will likely be a transitional period, with frequency of negative pricing hours remaining high to start before subsiding more materially by the end of the quarter.
REsurety creates the REmap-powered State of the Renewables Market report every quarter to provide readers with data-driven insight into the emerging trends and value of renewables in U.S. power markets. We combine our domain expertise in power markets, atmospheric science, and renewable offtake to analyze thousands of projects and locations and summarize key findings here. All of the data behind this analysis is available via our interactive software tool, REmap.
The REmap-Driven Q3 2021 State of Renewables Report was released today! This report reveals the captured value of operational wind and solar projects in major US markets in Q3 2021, and highlights how those values have changed in each market over time. Data is aggregated from millions of data points across public and private sources to shed light on the value of renewable generation.
REmap’s new vPPA simulator feature allows users to backcast vPPA settlement at all project locations, enabling analysis of market performance through the lens of a generator or vPPA buyer.
vPPA settlements represent the value (or cost) of the unit-contingent contract-for-difference hedge settlements that result from a virtual Power Purchase Agreement (vPPA) with a project.
The results below show modeled¹ vPPA settlement values (in $/MWh) from the energy buyer’s perspective over the course of Q2. For potential vPPA buyers, this data answers the question: “If I signed a vPPA at prices available today, how would it have performed this past quarter?”
Modeled vPPA settlement outside of ERCOT generally resulted in a cost for the vPPA buyer, even assuming today’s competitive PPA prices². Within ERCOT, vPPA settlement favored the vPPA buyer, with settlement values surpassing $25/MWh at some Texas solar projects. The cost of purchasing renewable energy through a vPPA was greatest for energy buyers with a wind vPPA settling at SPP North Hub, SPP South Hub, or PJM AEP-Dayton Hub. Solar vPPAs were most costly for projects settling at PJM Eastern Hub or MISO Michigan Hub.
Q2 2021 Modeled vPPA Settlement for Energy Buyers
Figure 1: Q2 2021 Modeled vPPA Settlement for Energy Buyers. Values for locations/technologies with limited data are not shown or marked “NA”.
¹ Results use REmap data for operating projects, which includes modeled and observed hourly generation and observed market prices. Cell values represent the project with the maximum, minimum, or median project settlement value to an energy buyer for the quarter.
² vPPA prices used are from the LevelTen Q2 2021 PPA Price Index, which reports on PPA bids by hub and technology type.
2. Coastal Texas Wind Projects Join the Rest of the Pack
Coastal wind projects in Texas tend to experience higher wind speeds in the afternoon hours, which typically aligns well with afternoon periods of high demand and high power prices. The ability to generate during high priced afternoon hours means coastal projects typically benefit from a positive shape (also known as covariance), whereas wind projects in the rest of Texas tend to experience negative shape (i.e., hours of high generation are negatively correlated with hours of high power prices).
However, in Q2 2021, coastal projects were not quite as fortunate. Shape profiles throughout all of ERCOT were quite negative, including coastal projects. Projects directly along the coast experienced shape discounts of $7-9/MWh, in line with other projects throughout the state. Figure 2a puts that in context of other ERCOT projects in Q2 2020 and 2021.
Q2 2021 Average Shape Values for Operating ERCOT Wind Projects
Figure 2a: Q2 2021 Average Shape Values for Operating ERCOT Wind Projects. The range and distribution of shape values for operating wind projects in ERCOT in Q2 2020 & 2021. The arrow indicates where the shape value of coastal wind projects fell. Source: REmap.
As an example: Stella Wind Farm, a coastal project in Kenedy County, experienced -$7.36/MWh average shape in Q2 2021, while its prior 5 year average for the same quarter was $0.66/MWh.
Why did coastal Texas wind projects not do well relative to historical performance?
Continuing to use Stella Wind Farm as an example, we can review the hourly performance in REmap using the Hourly Data Explorer. Figure 2b below shows the hourly data for Stella from April, a month in which the project’s shape value dropped to -$9.32/MWh. The top chart shows the hourly real-time hub price at ERCOT South and the bottom chart shows the hourly observed energy from Stella over the entire month.
April 2021 Hourly Hub Price and Generation Data
Looking at Figure 2b, we can identify two periods of elevated prices, on April 11th and 13th, when prices spiked to over $1800/MWh.
Zooming into the relevant period in Figure 2c, we can see the hourly alignment between price and generation for those days. During both high price events, generation was fairly low.
Hourly Hub Price and Generation Data for April 11th and 13th
3. Wide Basis Spreads for Wind Projects in Northern MISO
Last quarter, nodal prices for operating wind projects across North Dakota, Southwest Minnesota and Iowa continued a year-long trend of decline–with a precipitous drop.
To use one project as an illustrative example, Emmoms-Logan Wind saw a -$17.30/MWh node-to-hub basis value in Q1 2021, which was among the lowest of any operating wind project in MISO that quarter. In Q2 2021, its node-to-hub basis plummeted to -$44.20/MWh³.
If we use Emmoms-Logan’s Q1 performance as a benchmark and compare it to the Q2 performance for other operating wind projects in these states, the sharp decline in basis becomes more obvious. Figure 3a below shows operating wind projects in MISO. The color scale denotes historical node-to-hub basis value for Q2 2021, and the dark red areas denote any project that experienced an average basis value lower than -$17.30/MWh.
Q2 2021 Node-to-Hub Basis for Operating Wind Projects in MISO
Figure 3a: Q2 2021 Node-to-Hub Basis for Operating Wind Projects in MISO. Average generation-weighted basis values calculated using Minnesota Hub. Source: REmap.
Figure 3b below shows the 12-month trailing basis for a handful of wind projects in Northern MISO, including Emmons-Logan, and illustrates that this trend has been over a year in the making, but dramatically accelerated in the past 12 months.
12-Month Trailing Generation-Weighted Basis for Selected MISO Wind Projects
Basis has been a known issue for project owners and operators and is increasingly a concern for vPPA buyers and offtakers who can be directly or indirectly impacted by basis depending on contract terms. Price data, provided by REmap, provides one critical piece of the puzzle. REmap’s generation data supplies the second critical piece, enabling users to see how much generation occurred in each hour and giving visibility into the impact of basis on project settlement.
³ Basis values are generation-weighted at the hourly level and use Minnesota Hub pricing. Generation is modeled. Actual results may differ.
REsurety’s CEO Lee Taylor offered insight into this new report by The Business Renewables Center (BRC), a program of Rocky Mountain Institute.
EXCERPT
The US corporate renewable market has grown by leaps and bounds in the past five years. Corporate procurement has rapidly expanded from a niche to a substantial part of the US electricity system—one that has cumulatively brought online over 12% of all utility scale wind and solar installed in the country today. However, risk mitigation solutions have not kept pace with a rapidly diversifying and expanding corporate market. The issue of buyer risk has been raised with increasing frequency over the last few years and the market must address this issue seriously and immediately. For its own long-term health, the market must move away from the current one-size-fits-all approach to a “many-sizes-for-all” approach to risk mitigation.
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