Tag: Lee Taylor

Clean Integration Podcast: Managing Intermittent Power Risks

Clean Integration Podcast by Soluna

Listen in as John Belizaire, CEO at Soluna Computing and Lee Taylor, CEO at REsurety discuss the challenge of intermittency in the renewable energy market. The podcast covers REsurety’s impact on the clean energy economy through their innovative tools like Locational Marginal Emissions (LMEs) and hedging strategies.

The Clean Integration Podcast features experts in the renewable energy industry discussing the path to making renewables the primary, most affordable energy source. The podcast is sponsored by Soluna, a utility-scale developer that combines renewable energy power plants with high-performance computing facilities.

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.

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MEDIA ADVISORY: Solar + Wind Finance & Investment Summit

A year since the February 2021 power crisis in Texas, how have renewable energy hedge markets changed?

ERCOT lessons include new ways to incentivize generators to stay online when their electrons are most needed

BOSTON, Feb. 28, 2022 – Financial hedging tools used to manage clean energy generation and procurement risk have seen major changes in the past year, after the 2021 deep freeze in Texas upended power markets and resulted in outsized gains and losses for many in the industry. 

In an effort to limit their risk during such extreme weather events, many clean energy power producers have returned their focus to traditional as-generated power purchase agreements where operational shutdowns during price spikes are typically permitted with limited or no penalties. 

Lee Taylor, co-founder and CEO of REsurety will be featured on a panel at the Solar + Wind Finance & Investment Summit.
Lee Taylor, co-founder and
CEO of REsurety

The result could be a reduction of demand for clean energy from financially-motivated buyers, as well as a reduction in grid resiliency, warns Lee Taylor, CEO of REsurety, who will speak at the Solar + Wind Finance & Investment Summit next Monday in Scottsdale, Arizona. “If project shutdowns during periods of high demand have a limited impact on a project owner, there will be no incentive for resiliency, ” he says. 

Taylor is not alone in that view. Jay Bartlett of Resources for the Future wrote last March in the aftermath of the Texas deep freeze, blackouts, and $9,000-a-megawatt-hour power rates:

“The Texas power crisis has shown how different sales and hedge structures create very different levels of incentives for a wind project to generate during times of scarcity. While most attention focuses now on projects that either sustained great losses or earned windfall profits, more alarming over the long term are projects that were financially unaffected by the crisis. Those generators may have had little motivation to produce power during a time of great need. Appropriate incentives may not guarantee power supply—clearly, they did not last month—but aligning incentives between wind projects and system needs will better promote beneficial investments and operations. As wind and solar comprise an increasing percentage of power generation, well-designed hedge structures could prove instrumental to power system reliability.”

One solution is a hybrid between historically metered generation and proxy generation-based settlement methods. Future offtake contracts, such as vPPAs, can settle on metered generation but proxy generation (which represents what a project should have produced assuming normal operations and project availability) is utilized to calculate the financial impact of project operations. If that impact exceeds a materiality threshold, damages are owed by the project up to a cap. The materiality threshold and cap on damages would be agreed to by the project and the offtaker.

 “The goal is to preserve the best of both worlds,” says Taylor. “Projects understandably don’t want to bother with calculating proxy generation when the project is operating normally, and after winter storm Uri, projects are no longer comfortable with uncapped financial exposure to operations. This contracting method addresses both of those concerns, while preserving the offtaker’s interest in quantifying the financial cost of a project’s operational performance, and having some recourse when that cost is material.”

Taylor will elaborate during the panel, “Focus on Potential Gamechangers 1: Implementing Changes to the Hedge Market,” at 2:45 pm Mountain Time on Monday, March 7. Moderated by James T. Tynion III, Partner, Morgan, Lewis & Bockius, the panel will also feature Andrew Ehrlickman, Vice President, Brookfield Asset Management. The session promises to address how the financial fallouts from extreme weather events “have completely restructured the entire hedge industry by exposing huge risks lurking in the periphery.” 

The speakers will provide a deep dive into the long-term effects of recent freezes, heat waves, and storms; the changing risk appetites of parties and updated valuations in hedge calculations; and new hedge structures that are emerging. Also on the agenda: How to value weatherization, impacts on tax equity, and the appeal of merchant projects.

REsurety provides market intelligence, asset insight and risk management tools for clean energy sellers, buyers, investors and advisors. REsurety is a sponsor of the Solar + Wind Finance & Investment Summit, and will be at Table 96 where meetings can be scheduled. For media interviews with CEO Lee Taylor in person or by phone, please contact Allison Lenthall, [email protected], 202-322-8285.

About REsurety
REsurety is the leading analytics company empowering the clean energy economy. Operating at the intersection of weather, power markets and financial modeling, we enable the industry’s decision makers to thrive through best-in-class value and risk intelligence, and the tools to act on it. For more information, visit www.resurety.com or follow REsurety on LinkedIn.

Covariance risk: What it is and how to manage it

Norton Rose Fulbright’s June 2019 Project Finance NewsWire features an interview with Lee Taylor, REsurety’s CEO on covariance risk and how to manage it. It starts on Page 21. The article is based on a Feb. 2019 Currents Podcast.

Project sponsors, banks and tax equity investors in transactions with hedges may be overlooking some risks that wind projects are bearing. Each risk should be borne by the party best able to manage it. In some deals, this may not be happening.

One such risk is covariance risk.

There has been a fundamental shift in how electricity is sold by independent generators. As utilities cut back on the amount of electricity they are buying under long-term contracts from independent generators, financial parties, like banks and commodities firms, entered the market to buy power. Utilities have tended to buy “as-generated power,” meaning they pay a fixed price regardless of how much power is generated and — critically — when it is generated. In contrast, financial parties typically buy power in fixed blocks: with a set volume of power every hour over the life of the contract.

Financial parties buy power this way either so that they can match up with a predictable load or, more commonly, so that they have a known volume of power to sell to the physical consumers of electricity.

Selling fixed volumes of power in every hour of a contract creates challenges for an electricity supplier like a wind farm. The owner of the project does not know, and has no control over, how much electricity it will produce in any given hour, and even though there are seasonal and diurnal averages, what actually happens in any hour is highly variable.

Covariance

”Covariance risk” is the risk that a project will have a strong (typically negative) relationship between generation and price — so an hour of abnormally high generation will correspond to a low power price, and vice versa. While this condition can limit the value of power from a merchant wind farm relative to baseload energy, it is particularly challenging when the project has made fixed hourly delivery commitments (physically or financially) as the project not only misses out on revenues during high price hours, but is in fact a buyer of energy during those hours due to a need to purchase any shortfall between its hourly commitment and its hourly generation.

Chances are the reason the project came up short is a shortage of fuel: the wind died. And if the wind dies at a single project, it likely died at all of the neighboring projects — which means overall energy supply to the region has fallen, driving up energy prices — so the cost to cover the generation shortfall will be expensive.

To put this condition in financial terms, the current cap on energy price in ERCOT during a supply scarcity event is $9,000. Suppose a large wind farm in ERCOT has committed to sell 50 megawatt hours of electricity during a certain hour for a fixed price of $20 a MWh. It is a hot day in August. The wind dies and power prices spike to $9,000 a MWh in that hour. The project is at risk of having to buy 50 MWh at $9,000 each just to sell them under the existing contract for $20 each — a net cost to the project of $449,000 for a single hour.

The insurance markets are typically better positioned to absorb that kind of risk than are independent generators because insurers have a much greater capacity to absorb and diversify that risk.

An insurer can hold wind risk in Texas, solar risk in Australia, hydro risk in Uruguay, and so on, with the idea that extreme weather patterns are unlikely to hit every area simultaneously. The ability to diversify the risk makes the insurer the party best able to manage location-specific, weather-driven risks.

Balance of Hedge

Renewable generation projects can manage covariance risk through a hedging product called a “balance of hedge.”

The balance-of-hedge product is designed for projects that will sign or have already signed a hedge with a bank or commodity trader to swap floating market prices for fixed prices on fixed volumes of power. It transfers the risk of being short during high prices and long during low prices. The insurer will assign an expected value to all of the residual excess short and long positions. Because of the enormous amount of potential volatility, the insurer will price the risk below the expected value so that it should make money for the insurer during an “average” weather year, but will eliminate the project’s exposure to extreme weather conditions.

For example, July 2018 was very hot in Texas. Power prices spiked during a period when wind speeds were low. Anyone with a bank hedge that month probably had a rough month. A balance of hedge smooths out the pattern of cash flow for a project with a fixed-quantity price hedge. The underlying hedge converts the floating revenue for a project selling its electricity into ERCOT into a fixed revenue stream, but if it is a fixed-volume hedge, it does not protect a project from coming up short on the fixed volume that the project has promised and having to cover the shortfall in floating revenue owed under the hedge. The balance of hedge covers this risk.

There may be only a limited appetite for a balance of hedge at the project level for an existing tax equity deal. The tax equity investor and lender have already underwritten the transaction based on their evaluations of the power contract and hedge. Most sponsors would do better to have the project company sign the balance-of-hedge contract with the insurance company when the tax equity is first put in place. Doing it later requires consent from the tax equity investor, who may be reluctant to reopen a transaction, especially as it may require a re-marking of the position.

From a credit perspective, a letter of credit is typically used as collateral for the balance of hedge. This is often posted at the sponsor level. However, if the sponsor lacks access to an LC facility or wants to offer a lien instead, then the lien must be harmonized with the lien-based collateral that has probably been provided to the bank that is the counterparty to the main bank hedge. Anyone entering into a bank hedge without putting the balance of hedge in place at the same time should negotiate for the ability to use incremental liens as collateral for the insurance company that is the counterparty under any balance of hedge put in place later.

REsurety is not an insurer. We support balance of hedge transactions by providing analyses to insurers who use those analyses to offer and set the price of balance-of-hedge products. While other insurers are working to enter the market, the vast majority of balance-of-hedge contracts — and other related products — have been offered through a partnership between Allianz Risk Transfer and Nephila Climate.

Assessing the Value

A white paper on our website called “The P99 Hedge that Wasn’t” looks at the hourly performance of every operating wind farm in Texas. We were able to use this data to analyze how a wind farm that purchased a bank hedge would have performed historically, including through the 2014 polar vortex, the 2011 heat wave and other major weather-driven events.

That said, a perfect view of the past cannot guarantee future performance. A good example occurred when coal plants dropped out of the ERCOT generation fleet in 2017 and the ERCOT reserve margin shrank, increasing the likelihood of high price events during low wind periods. Predicting how pricing will be affected in a market with less thermal generation and much more wind and solar is hard. You are predicting how various weather and commodity conditions will interact with a generation stack that has never existed before. Every month there are more wind farms in Texas than ever before. We spend a lot of time looking at how projects and markets performed over the last five or six years under high and low gas prices, high and low temperatures and high and low wind speeds, and analyzing how this is likely to change over time.

That depth of analysis is critical to insurers’ ability to underwrite balance-of-hedge and related products. Fundamentally, our job is to build a distribution of risk. We provide information around that distribution and identify sources of uncertainty and insurers like Allianz and Nephila use that information to offer and price products.

On average, the market has underestimated covariance risk in bank hedges and, in particular, in the Texas market. Utilities have taken this risk historically under long-term contracts where they commit to take whatever electricity is generated.

The covariance issue is weather-driven. High heat or extreme cold during low weather events is what causes significant changes in the as-generated versus fixed quantities of power. The year 2018 saw some unusually cold temperatures in January and some unusually high ones in July. This led to a significant amount of dislocation, and the market woke up to the exposures that projects are bearing.

Now we are in 2019, and we see pretty diverging views across the market about what happened last year and how it might change. If we re-live a 2011 heat wave with the current generation supply stack, nobody knows how that will play out, but it is clear that it would be a significantly bad event for almost any wind project with a standard fixed-quantity hedge.

Solar v. Wind

Solar developers should think about covariance risk the same way as wind developers.

A lot of solar is being built in Texas, in part because power prices are high in the summer when wind speeds are low, so there is an attractive pricing dynamic for a solar operator. At the same time, the whole solar industry is aware of what happened in California with the duck curve. More solar electricity is generated during the middle the day than the grid requires. If the grid sheds the excess electricity, it can depress power prices in the same way that happens during an especially windy hour in the winter in Texas.

The prevailing view currently is that the extremely rapid growth of wind in Texas compared to solar creates a great opportunity, but the solar industry in Texas has the potential to become a victim of its own success. The question is where is the equilibrium reached, and how big of a role storage will play.

The focus on Texas has been driven by the fact that most of the financial hedging for wind projects to date has been in ERCOT. However, interest in hedges is expanding into other regions like SPP and MISO where the same relationship can be seen between wind speeds and power prices. There is less wind in PJM, so there is less of the causal issue of high wind speeds pushing down power prices, but there is still the same general correlation of lower prices during high wind periods. The severity of the issue varies from one market to the next, but it affects every power plant whose output is intermittent.

The longest balance of hedge being offered today is 10 years. Pricing gets more expensive the longer the term in some markets, but not in all markets.

The concern about price spikes during low wind events in the summer is most acute for the next three to four years in Texas. That is partly due to a belief that solar capacity additions will help to moderate price spikes during the summer months when extreme covariance risk is most acute.

Corporate Buyers

The issue of covariance is not unique to the seller of electricity. If a project enters into an as-generated power purchase agreement with a corporate buyer, it will have transferred the covariance risk away from the project and to the buyer of electricity.

Microsoft has been the most active in thinking about and managing this risk, and it was the first to embrace a solution through use of a “volume firming agreement.”

A “volume firming agreement” works in much of the same way as a balance of hedge: it locks in a fixed value to the sum of the hourly short and long positions held by a corporate buyer who is meeting a fixed-shape load with an as-generated PPA.

Suppose a data center requires 50 megawatts of power every hour to run its operations. If it has signed an as-generated PPA with a wind farm to manage the risks of its electricity costs, how well that PPA performs as a hedge on energy costs depends on the correlation between the wind project’s output and power prices. For example, if the wind dies and power prices spike and the data center still must buy 50 megawatts of power each hour, the data center is buying very expensive power despite the fact that it signed a PPA to mitigate energy price risk.

Microsoft decided it would like to shed that risk to an insurer in the same way that a project does.

Usually, the underlying PPA has already been signed and the volume firming agreement is added after the fact as a way to convert the PPA into something that is significantly more effective in managing the energy costs of a corporate buyer.

However, we are starting to see more corporate offtakers look at putting a volume firming agreement in place at the same time the PPA is signed. That gives them certainty about how their PPAs will perform as expected from the start.

In some cases, the project selling power under the PPA may or may not be aware of the volume firming agreement as the corporate buyer has a view that it should be free to manage its risk however it chooses without having to involve the project. In other cases, it becomes a three-party discussion among the project, the corporate buyer and the insurer. In either case, the PPA and the volume firming agreement are separate contracts.

Overall, projects and their investors should expect offtake arrangements to be much more dynamic in the future. Whereas traditional 20+-year busbar PPAs managed nearly all of a project’s risks for a long period, today offtake contracts are typically shorter term and have various flavors of risk management. 

The Next Generation Of Risk Management For Renewable Energy

Contributing author, REsurety’s CEO Lee Taylor, breaks down how Proxy Revenue Swaps work, and outlines the benefits of risk mitigation tools.

Reposted as in North American Windpower.

Before the rise of renewables, when our electricity system primarily relied on fossil fuels, the main risk driving power markets was the relationship between the price of the fuel being burned and the price of power in the market.

Enter renewable energy, where the fuel is free – rendering fuel price risk irrelevant. Unfortunately, that strong economic benefit comes with a cost: While the price of fuel for a wind farm is certain, the volume of fuel that shows up in a given hour, month or year is uncertain. This transition from fuel price-driven risk to fuel volume-driven risk created the need for a new generation of risk management products.

Renewables in general and wind in particular have been significant contributors to power markets for many years, so one might reasonably ask – why all the attention on this “new” risk now? Until fairly recently, the predominant buyers of renewable energy were utilities, often buying to satisfy renewable portfolio standard (RPS)-driven obligations. The mechanism used by utilities – the power purchase agreement (PPA) – secured a fixed price of energy for the project regardless of when and how much of that energy was produced. As a result, much of a project’s fuel volume-driven risk was transferred to utilities and, ultimately, to the utilities’ customers.

Today, with utilities making up an ever-smaller percentage of renewable energy buyers, fuel volume-driven risks are being pushed back onto project owners. One example is the fixed-volume contract-for-difference hedging structure, also known as a “P99 hedge”. As we discussed in a 2018 white paper, The “P99 Hedge” That Wasn’t, a P99 hedge is a great tool for mitigating commodity market exposure, but it does not address – and, in fact, often increases – a project’s financial exposure to fuel volume-driven risks.

As renewable energy project owners realized the scale and complexity of new risks they were taking on, they began to look for solutions. Insurance markets quickly started offering those solutions, with the first, and so far most successful, being the proxy revenue swap (PRS). Typically offered by an insurer, a PRS guarantees a certain level of revenue to the project, irrespective of power prices and when and how much the wind blows.

proxy revenue swap graphic

So how does a PRS transaction actually work? Instead of guaranteeing a fixed price of power ($/MWh), as does a PPA or a P99 hedge, a PRS guarantees a fixed value ($/year). In exchange for that guaranteed value, the project pays the insurer the variable value of “proxy revenue.”

Proxy revenue is calculated on an hourly basis as: i) the volume of energy the project should have produced during that hour, given the fuel resource measured at each individual wind turbine, multiplied by ii) the price of energy at the settlement point (typically a hub) during that hour.

To illustrate, assume an insurer guarantees an annual value of $10 million of proxy revenue. Once operational, the project has a poor first year (earning $5 million in proxy revenue) and a strong second year (earning $15 million). In the first year, the insurer pays the project the shortfall between the earned proxy revenue and the guaranteed value (i.e., the insurer pays the project $5 million).

In the second year, the project pays the insurer the excess between the earned proxy revenue and the guaranteed value (i.e., the project pays the insurer $5 million). In both years, the project earns – after the PRS payments are made – $10 million, and the variability of proxy revenue is absorbed by the insurer.

Along with the PRS, other hedging products have been developed to give project owners options based on their specific project requirements. For example, if a project already has a P99 hedge but wants to manage the risks driven by uncertain volumes of hourly generation, it can use a balance of hedge (BoH). A BoH transfers the fuel volume-driven risk from the project to the insurer. When combined, the P99 hedge and BoH recreate the same certainty of value for a project as does a PRS.

Volume firming agreement graphic

Innovations in risk management strategies are not limited to addressing risks held by clean energy sellers (project owners). Commercial and industrial (C&I) buyers of clean energy have become increasingly concerned with the fuel volume-driven risk they are taking on through their PPA contracts. In signing a PPA, C&I buyers take on the same volume and timing-of-generation risks that utilities take on – but unlike a utility, C&I buyers don’t have a rate base to rely on to help absorb volatility and risks.

In response, we again see insurance markets providing risk mitigation solutions – often in collaboration with leading C&I buyers. A great example comes from Microsoft, which last year announced its co-development and use of a volume firming agreement (VFA). A VFA enables C&I buyers to eliminate the financial exposure to fuel volume-driven risks inherent to PPAs. Combined with a PPA, a VFA provides C&I buyers certainty in their future energy consumption costs – irrespective of when and how much the wind blows.

As wind and solar markets mature, the appetite for clean energy purchasing has expanded from utilities to a much larger world of C&I buyers, banks and insurers. That’s great news for the growth of our industry and the sustainability of our planet, but it requires an understanding of the new risks being taken on.

Importantly, it also requires embracing new tools available to manage those risks. At first glance, this can be daunting, but with the increasingly widespread adoption of these new risk management tools, they are rapidly becoming standard operating procedure for our industry.

Lee Taylor is CEO of REsurety Inc., a risk management and information services company based out of Boston. He can be reached at [email protected].