Category: Report

Q3 2022 State of the Renewables Market Report

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

Carl Ostridge
SVP of 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.

Q3 2022 Report Download

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Q2 2022 REmap Report

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

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.

Q2 2022 REmap Report Download

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June 2022 Project Finance NewsWire

How Hedges Have Changed Since Uri, Lee Taylor, REsurety CEO

Project Finance NewsWire spotlights developments affecting project finance and the energy sector; you can find Lee Taylor’s feature on page 15.

AN EXCERPT:

Cover page of the June 2022 Project Finance NewsWire report.
A publication from Norton Rose Fulbright

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.

Continue reading by downloading the PDF.

Q1 2022 REmap Report

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.

Q1 2022 State of the Renewables Market Report

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Blair Allen, director, software customer success, REsurety

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.

Q4 2021 REmap Report

REmap Q4 2021 Report

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.

REmap Q4 2021 Report

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Q3 2021 REmap Report

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.

We hope you appreciate the insight!

Cover of the REmap-powered State of the Renewables Market report for Q3 2021.

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Q2 2021 REmap Report

1. Modeled Q2 PPA Performance Across Major Hubs

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

vPPA-settlement-values
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

Avg-Shape-2
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

Hub-Gen

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

April-11-and-13

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

Avg-Basis
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

Trailing-Basis
Figure 3b: 12-Month Trailing Generation-Weighted Basis for Selected MISO Wind Projects. Source: REmap.

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.

A Corporate Purchaser’s Guide to Risk Mitigation

Report-A-Corporate-Purchasers-Guide-to-Risk-Mitigation-Cover

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.

Fill out the form below to access the report.

Report-A-Corporate-Purchasers-Guide-to-Risk-Mitigation-Cover

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